Document ID: PHMSA-2011-0023-0464
Agency: phmsa
Document Type: Rule
Title: Pipeline Safety: Safety of Gas Transmission Pipelines:  Maximum Allowable Operating Pressure Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments
Posted Date: 2019-10-01T04:00Z

[Federal Register Volume 84, Number 190 (Tuesday, October 1, 2019)]
[Rules and Regulations]
[Pages 52180-52257]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2019-20306]

[[Page 52179]]

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  

[[Page 52180]]

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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 713-272-2855. General information: 
Robert Jagger, Senior Transportation Specialist, by telephone at 202-
366-4361.

SUPPLEMENTARY INFORMATION:

I. Executive Summary
    A. Purpose of the Regulatory Action
    B. Summary of the Major Provisions of the Regulatory Action in 
Question
    C. Costs and Benefits
II. Background
    A. Detailed Overview
    B. Pacific Gas and Electric Incident of 2010
    C. Advance Notice of Proposed Rulemaking
    D. National Transportation Safety Board Recommendations
    E. Pipeline Safety, Regulatory Certainty, and Job Creation Act 
of 2011
    F. Notice of Proposed Rulemaking
III. Analysis of Comments, GPAC Recommendations and PHMSA Response
    A. Verification of Pipeline Material Properties and Attributes--
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,

[[Page 52181]]

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

[[Page 52182]]

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

[[Page 52183]]

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

[[Page 52184]]

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.
---------------------------------------------------------------------------

    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

[[Page 52185]]

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

[[Page 52186]]

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.
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    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,

[[Page 52187]]

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.
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    \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

[[Page 52188]]

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\
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    \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\
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    \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.
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    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

[[Page 52189]]

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.
---------------------------------------------------------------------------

    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.

[[Page 52190]]

    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

[[Page 52191]]

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

[[Page 52192]]

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

[[Page 52193]]

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

[[Page 52194]]

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

[[Page 52195]]

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

[[Page 52196]]

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:
    (1) Grandfathered pipe, in direct response to section 23(d) of the 
2011 Pipeline Safety Act and NTSB recommendation P-11-14;
    (2) Pipe for which documentation is inadequate to support the MAOP, 
in direct response to section 23(c) of the 2011 Pipeline Safety Act; 
and
    (3) Pipe that has experienced a reportable in-service incident 
since its most recent successful subpart J pressure test due to an 
original manufacturing-related defect; a construction-, installation-, 
or fabrication-related defect; or a cracking-related defect, including, 
but not limited to, seam cracking, girth weld cracking, selective seam 
weld corrosion, hard spots, or stress corrosion cracking.
    It is important to note that a given pipeline segment for which the 
MAOP reconfirmation process would apply might fit into one, two, or all 
three of these proposed categories. For pipeline segments where records 
of the pipeline physical properties and attributes to substantiate the 
current MAOP are not documented in traceable, verifiable, and complete 
records, only those segments located within an HCA or a Class 3 or 
Class 4 location would be subject to the MAOP reconfirmation process 
under the NPRM.
    This proposal directly correlates to section 23 of the 2011 
Pipeline Safety Act and NTSB recommendation P-11-14 regarding the need 
for spike hydrostatic testing where in-service incidents have occurred. 
The NTSB recommended such testing for all pipe manufactured before 
1970.
    For pipeline segments where operators established the MAOP in 
accordance with the grandfather clause at Sec.  192.619(c) (i.e., 
pipeline segments where the MAOP is based upon the highest actual 
operating pressure records from a 5-year interval between July 1, 1965, 
to July 1, 1970, and where operators therefore do not have pressure 
test or material property records) or for segments with a history of 
in-service incidents caused by cracks or crack-like defects, PHMSA 
proposed to restrict the applicability of MAOP reconfirmation to HCAs, 
Class 3 or Class 4 locations, or MCAs, if the MCA segment can 
accommodate an ILI tool. The proposed inclusion of pipeline segments in 
these locations and with these traits slightly expand on the mandate 
contained in section 23 of the 2011 Pipeline Safety Act, which applied 
only to previously untested pipeline segments operating at a pressure 
greater than 30 percent SMYS located in an HCA.
    In recommendation P-11-14, the NTSB recommended that all pipe 
manufactured before 1970 be subjected to a hydrostatic pressure test 
that would include a spike hydrostatic test, which PHMSA considered in 
its process for reconfirming MAOP. PHMSA's preliminary evaluation 
concluded that doing so may not be cost-effective, since a large amount 
of such pipe could be in remote locations where the likelihood of 
personal injury or property damage as a result of an incident would be 
low.
    PHMSA's proposal expanded the applicability of MAOP reconfirmation 
beyond the minimum required by the congressional mandate to include 
pipe operating at less than 30 percent SMYS. In addition, the NPRM 
expanded the location criteria to include some non-HCA locations in the 
form of MCAs and Class 3 and Class 4 locations. As PHMSA proposed in 
the definitions section of the NPRM, MCAs are areas that, while not 
meeting the HCA criteria, include 5 or more persons or dwellings 
intended for human occupation or are otherwise locations where people 
congregate, including the right-of-ways of major roadways. See section 
H of this final rule for additional background on the MCA definition. 
The NPRM also specified that the MAOP reconfirmation process would 
apply only to MCA pipeline segments able to accommodate an ILI tool. 
This provision would not preclude an operator from choosing to conduct 
a pressure test, but it would avoid forcing operators to conduct a 
pressure test because the pipeline segment was not ``piggable.''
2. Summary of Public Comment
    Many stakeholders provided input on the proposed provisions in 
Sec.  192.624 that require MAOP reconfirmation for pipeline segments 
previously excluded from testing by the grandfather clause, pipeline 
segments without adequate documentation to substantiate the current 
MAOP, and pipeline segments that have experienced a reportable in-
service incident.
    Regarding the first criterion above, several commenters, including 
INGAA, AGA, and NAPSR, generally supported the provision requiring 
operators of pipeline segments where the MAOP was established via the 
grandfather clause to reconfirm the MAOP of those segments. Several of 
the pipeline industry trade associations and industry entities, 
however, did not support the proposed application of these criteria to 
all grandfathered pipeline segments within HCAs, Class 3 and Class 4 
locations, and Class 1 and Class 2 piggable segments within MCAs. Gas 
Processors Association's Midstream Association (GPA) and AGA stated 
that while they support the congressional mandate to conduct testing to 
confirm the material strength of previously untested gas transmission 
pipelines in HCAs that operate at a pressure above 30 percent SMYS, 
they oppose the proposed provisions which extend to additional pipeline 
segments. INGAA and Washington Gas supported the applicability of MAOP 
reconfirmation in MCAs for pipelines operating at greater than or equal 
to 30 percent SMYS but disagreed with the proposed provisions that 
included MCA pipelines operating at less than 30 percent SMYS.
    Some citizen groups, including PST, expressed concern that the 
proposed changes regarding the grandfather clause did not go far enough 
and suggested that PHMSA should fully implement the recommendations set 
forth by the NTSB. They stated that PHMSA should eliminate the 
grandfather clause given that the proposed provisions would not include 
the following groups of pipelines: (1) Pipelines in non-HCA areas 
within Class 1 and Class 2 locations; and (2) pipeline segments for 
which there is an inadequate record of a hydrostatic pressure test in 
areas newly designated as an MCA that are not capable of being assessed 
by an in-line tool. Conversely, Northeast Gas Association (NGA) stated 
that PHMSA should retain the grandfather clause as it prevents 
existing, historically safe, and maintained pipelines from being 
subjected to unwarranted requirements.
    For pipeline segments where operators do not have adequate 
documentation to support the current MAOP and that PHMSA proposed would 
be subject to the new MAOP reconfirmation requirements, some commenters 
stated that they support the

[[Page 52197]]

requirement to the extent that it is consistent with the congressional 
mandate to reconfirm MAOP for pipeline segments with insufficient 
records within Class 3 and Class 4 locations and Class 1 and Class 2 
HCAs. These commenters further stated that Sec.  192.624(a)(2) within 
the proposed MAOP reconfirmation requirements should be revised to 
clarify that it applies only to those gas transmission pipeline 
segments in HCAs and Class 3 and Class 4 locations that were 
constructed and put into operation since the adoption of the Federal 
Pipeline Safety Regulations in 1970, stating that otherwise Sec.  
192.624(a)(2) would apply to those pipelines put into service prior to 
the implementation of Federal regulations where the requirement to 
maintain a pressure test record does not apply. Some commenters also 
stated that PHMSA should revise Sec.  192.624(a) within the proposed 
MAOP reconfirmation requirements to make clear that operators that have 
used one of the proposed allowable methods for establishing MAOP in 
Sec.  192.624(b) other than the pressure test method are not required 
to have a pressure test record to comply with the record requirements 
of the section. Washington Gas asserted that the MAOP reconfirmation 
requirements should apply to only pipeline segments in HCAs that 
operate at a pressure of greater than or equal to 30 percent SMYS. 
Other commenters, including Xcel Energy, stated that the proposed 
provisions should allow operator discretion regarding what constitutes 
a reliable, traceable, verifiable, and complete record to determine the 
necessary documentation to support a pressure test record and the 
necessary material properties for MAOP verification. Additionally, AGA 
recommended the deletion of the phrase ``reliable, traceable, 
verifiable, and complete'' from the proposed MAOP reconfirmation 
provisions in Sec.  192.624(a)(2). Similarly, other commenters, 
including INGAA, recommended omitting ``reliable'' from the phrase and 
provided a suggested definition for ``traceable, verifiable, and 
complete.''
    Lastly, with regard to the third category of applicable pipeline 
segments to the proposed MAOP reconfirmation requirements, many 
commenters either disagreed or requested clarification for the 
requirement that MAOP must be reconfirmed in cases where an in-service 
incident occurred due to a manufacturing defect listed under Sec.  
192.624(a)(1). For example, INGAA stated that an operator can evaluate 
such manufacturing defects more effectively through ongoing operations 
and maintenance activities rather than through MAOP reconfirmation, and 
that the defects PHMSA is concerned with are already addressed through 
integrity management. Similarly, Boardwalk Pipeline stated that 
pipelines that have experienced an in-service incident because of the 
listed defects in Sec.  192.624(a)(1) should be subject to integrity 
management measures rather than MAOP reconfirmation. TransCanada and 
TPA recommended adding text to the applicability section of the MAOP 
reconfirmation requirements that would exclude a pipeline segment from 
such requirements if the operator has already acted to address the 
cause of the reported incident. Additionally, one commenter suggested 
that this requirement should apply only to pipelines in HCAs. Some 
commenters, including AGA and Consolidated Edison of New York (Con Ed), 
also requested additional time to comply with the proposed MAOP 
reconfirmation provisions, asserting that operators would be required 
to replace many of their transmission mains to comply with the new 
requirements because their current records would not be satisfactory. 
Due to the urban density and scale of the service areas of certain 
operators, AGA and Con Ed stated that this replacement process would 
take longer than the 15-year schedule provided in the rule. One 
commenter suggested that if the applicability criteria for pipeline 
segments with in-service incidents and manufacturing defects remains in 
the rule, it should be limited to a more contemporary time frame, such 
as a rolling 15-year window or those in-service incidents that have 
occurred since 2003. Pipeline Safety Trust, on the other hand, stated 
that the proposed timeframe of 15 years is too long for operators to 
reconfirm MAOP in HCAs and complete critical safety work, and they 
urged PHMSA to adopt significantly shorter timelines in the final rule.
    Additionally, AGA asserted that the proposed MAOP provisions do not 
address how the completion plan and completion dates of the section 
would apply to pipelines that might experience a failure in the future 
and would then be subject to the proposed MAOP reconfirmation 
requirements, or for pipelines that are not currently located in a MCA 
but may be in the future. Lastly, INGAA stated that section 23 of the 
2011 Pipeline Safety Act requires that PHMSA consult with the Chairman 
of the Federal Energy Regulatory Commission (FERC) and State regulators 
before establishing timeframes for the testing of previously untested 
pipes, and it is not evident that PHMSA has complied with this 
requirement.
    As a general comment, several stakeholders, including AGA, 
Louisville Gas & Electric, New Mexico Gas Company, National Grid, NW 
Natural, PECO Energy, TECO Pipeline Gas, and New York State Electric 
and Gas (NYSEG), proposed an alternative method for MAOP reconfirmation 
where operators would execute two separate sets of actions that they 
stated could be performed simultaneously or separately. First, 
operators would either assess high-risk gas transmission pipelines 
using a pressure test or an alternative technology that is determined 
to be of equal effectiveness. Operators would categorize these 
pipelines in three tiers and schedule them for testing depending on the 
pipeline's SMYS and class location. Second, operators would use an ILI 
tool on all gas transmission pipelines, regardless of class location, 
that are capable of accommodating ILI tools. The ILI tool used would be 
qualified to find defects that would fail a subpart J pressure test. 
These commenters stated that this alternative methodology was necessary 
because the proposed provisions would create operational inefficiencies 
that would likely result in excessive cost and limited public benefit. 
In addition to providing this alternative proposal, many of these 
commenters provided other assorted comments on the proposed provisions.
    At the GPAC meeting on March 26, 2018, the GPAC recommended that 
PHMSA revise the scope of the proposed MAOP reconfirmation provisions 
by excluding lines with previously reported incidents due to crack 
defects. To go along with this, the GPAC also recommended PHMSA create 
a new section in subpart O of part 192, the natural gas IM regulations, 
to address pipeline segments with crack-related incident histories. 
Doing these actions would eliminate the need for the proposed 
definitions of ``modern pipe,'' ``legacy pipe,'' and ``legacy 
construction techniques,'' and the impact of this is discussed later in 
this document.
    The GPAC also recommended that the MAOP reconfirmation provisions 
be revised to apply to pipeline segments in HCAs or Class 3 or Class 4 
locations that do not have traceable, verifiable, and complete records 
necessary to establish MAOP under Sec.  192.619. Previously, the 
provisions were applicable to those pipeline segments without 
traceable, verifiable, and complete subpart J pressure test records. 
Similarly, the GPAC recommended that the MAOP

[[Page 52198]]

reconfirmation provisions only apply to grandfathered pipelines in 
HCAs, Class 3 or Class 4 locations, or MCAs able to accommodate 
inspection with ILI tools, and that have MAOPs producing a hoop stress 
greater than or equal to 30 percent SMYS. In the NPRM, the provisions 
applied to all grandfathered pipelines in those locations regardless of 
SMYS. In making this recommendation, the GPAC also suggested PHMSA 
review the costs and benefits of applying the MAOP reconfirmation 
provisions to non-HCA Class 3 and Class 4 grandfathered pipe with MAOPs 
less than 30 percent SMYS.
    During the meeting on March 27, 2018, the GPAC also recommended 
revisions to other sections related to the applicability of MAOP 
reconfirmation provisions, including withdrawing the proposed revisions 
to Sec.  192.503, which tied general requirements of the subpart J 
pressure test to alternative MAOP and MAOP reconfirmation provisions, 
and withdrawing the proposed revisions to Sec.  192.605(b)(5), which 
cross-referenced several sections related to the MAOP reconfirmation 
requirements to the requirements regarding an operator's procedural 
manuals.
    The GPAC also examined the provisions related to the completion 
date of these actions and recommended that PHMSA revise the appropriate 
paragraph to account for pipelines that may be subject to these 
requirements in the future, such as for pipelines that are not in an 
HCA or Class 3 or Class 4 location now, but due to population growth or 
development may be in such a location in the future. More specifically, 
the GPAC recommended that an operator would have to complete all 
actions required by the MAOP reconfirmation provisions on 100 percent 
of their pipelines that meet the applicability requirements by 15 years 
after the effective date of the rule or as soon as practicable but no 
later than 4 years after the pipeline segment first meets the 
applicability conditions, whichever is later. The GPAC also recommended 
PHMSA consider a waiver or no-objection procedure if operators cannot 
meet the requirements within 4 years under this scenario.
3. PHMSA Response
    PHMSA appreciates the information provided by the commenters 
regarding the applicability of MAOP reconfirmation. After considering 
these comments and as recommended by the GPAC input, PHMSA is modifying 
the rule to address many of these comments.
    Regarding the applicability of the new MAOP reconfirmation 
requirements at Sec.  192.624, PHMSA notes that a simplistic repeal of 
the ``grandfather clause'' at Sec.  192.619(c) is not practical because 
it applies to gathering and distribution lines. As the proposed rule 
was primarily focused on the safety of gas transmission pipelines, a 
broad repeal of the grandfather clause was not contemplated in the 
proposed rule. Further, a major expansion of the MAOP reconfirmation 
requirements beyond the scope of the congressional mandate in the 2011 
Pipeline Safety Act would be costly, and the GPAC noted at the meeting 
on March 26, 2018, that there may be cost-benefit concerns to test all 
grandfathered pipelines. The GPAC recommended PHMSA analyze requiring 
operators to reconfirm the MAOP of all grandfathered lines, and PHMSA 
considered this as an alternative in the RIA.\65\
---------------------------------------------------------------------------

    \65\ See section 5.9.1 of the RIA for further details.
---------------------------------------------------------------------------

    In response to the comments received and the recommendations of the 
GPAC, PHMSA is modifying the applicability of the MAOP reconfirmation 
requirements as follows: (1) The applicability related to pipeline 
segments with past in-service incidents is being eliminated. As 
commenters mentioned, operational failures are already addressed within 
integrity management and other subparts of part 192. Section 192.617, 
for example, would require an operator of a gas transmission line that 
had an in-service incident caused by an incorrect MAOP to determine the 
proper MAOP of the segment before placing it back into service. Causes 
of in-service failures are also already incorporated into the risk 
analyses required by the current IM regulations. If the cause of an 
incident is an incorrect MAOP, for example, then operators would be 
required to reconfirm it following the incident within their IM 
program. However, PHMSA is adding a new paragraph to strengthen the IM 
requirements at Sec.  192.917(e)(6) to specifically include actions 
operators must take to address pipeline segments susceptible to cracks 
and crack-like defects. (2) PHMSA is also modifying the applicability 
of these requirements by specifying the MAOP reconfirmation 
requirements are applicable to pipeline segments that do not have the 
pipeline physical properties and attributes needed to establish MAOP 
documented in traceable, verifiable, and complete records, specifically 
those records required to establish and substantiate the MAOP in 
accordance with Sec.  192.619(a), including those records required 
under Sec.  192.517(a). More specifically, these requirements to verify 
MAOP would apply to such pipelines without traceable, verifiable, and 
complete records in HCAs and Class 3 and Class 4 locations as specified 
in the congressional mandate. Further, PHMSA is dropping the word 
``reliable'' from the applicability section of the regulatory text to 
be consistent with previous PHMSA advisory bulletins on this topic.\66\ 
(3) PHMSA is modifying the applicability of the MAOP reconfirmation 
provisions for ``grandfathered'' pipeline segments to pipelines with an 
MAOP greater than or equal to 30 percent of SMYS, as specified in the 
congressional mandate. In addition to these requirements applying to 
grandfathered pipelines in HCAs, PHMSA is retaining the MAOP 
reconfirmation applicability requirement for grandfathered pipeline 
segments in Class 3 and Class 4 locations and in piggable MCAs to 
address the NTSB recommendation on this topic. As per the committee's 
suggestion, PHMSA analyzed whether it would be feasible to make the 
MAOP reconfirmation requirements applicable to non-HCA Class 3 and 
Class 4 pipe operating below 30 percent SMYS. This analysis is 
presented as an alternative in the RIA for this rulemaking. Ultimately, 
PHMSA did not choose to include these categories of pipelines in the 
scope for the applicability of the MAOP reconfirmation requirements 
because the GPAC recommended it was cost-effective for the provision to 
only apply to pipe operating above 30 percent SMYS in Class 3 and 4 
locations and because those pipelines present the greatest risk to 
safety.
---------------------------------------------------------------------------

    \66\ Pipeline Safety: Verification of Records; 77 FR 26822; May 
7, 2012; https://www.govinfo.gov/content/FR-2012-05-07/pdf/2012-10866.pdf.
---------------------------------------------------------------------------

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

[[Page 52199]]

segments within 24 months of a change in class location.
    PHMSA also acknowledges that some commenters thought the 15-year 
compliance timeframe for MAOP reconfirmation was too long. PHMSA 
believes a 15-year timeframe is necessary to be consistent with Sec.  
192.939, which allows operators to use a confirmatory direct assessment 
to confirm their MAOP in two, 7-year inspection cycles. This timeframe 
was discussed by the GPAC and was approved by unanimous vote. PHMSA 
will note that operators are required to have 50 percent of the 
applicable mileage completed within 8 years of the effective date of 
the rule. PHMSA would expect operators to prioritize and reconfirm the 
MAOP of the highest-risk segments first.
    PHMSA is also withdrawing miscellaneous revisions to Sec.  192.503, 
which tied general requirements of the subpart J pressure test to 
alternative MAOP and MAOP reconfirmation provisions, and miscellaneous 
revisions from Sec.  192.605(b)(5), which cross-referenced several 
sections related to MAOP requirements to the requirements regarding an 
operator's procedural manuals. These changes were made to simplify the 
regulations.
    Additionally, because PHMSA has eliminated pipeline segments with 
past in-service incident history from the scope of the MAOP 
reconfirmation requirements, PHMSA is striking the proposed references 
within the MAOP reconfirmation requirements to the alternative MAOP 
requirements at Sec.  192.620(a)(ii). Operators who used the 
alternative requirements to establish the MAOP of their pipelines were 
required to have complete documentation \67\ and therefore would not be 
subject to the MAOP reconfirmation requirements. If an operator had 
previously established the MAOP of a pipeline segment under the 
alternative MAOP requirements, but has since lost the records necessary 
to validate the alternative, they would have to reconfirm MAOP using 
the alternative MAOP requirements, or apply for a special permit to 
continue operation.
---------------------------------------------------------------------------

    \67\ ``Pipeline Safety: Standards for Increasing the Maximum 
Allowable Operating Pressure for Gas Transmission Pipelines; Final 
Rule;'' October 17, 2008; 73 FR 62148. The effective date of the 
rule was November 17, 2008.
---------------------------------------------------------------------------

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

B. MAOP Reconfirmation--Sec. Sec.  192.624 & 192.632

ii.--Methods

    In developing regulations to reconfirm MAOP where necessary, 
Congress mandated that PHMSA consider safety testing methodologies that 
include pressure testing and other alternative methods, including in-
line inspections, determined to be of equal or greater effectiveness. 
The NTSB recommended an expansive pressure test approach to address the 
safety issues identified in their investigation of the PG&E incident 
through recommendations P-11-14 and P-11-15. In response to the 
congressional mandate, PHMSA evaluated other methodologies and 
identified five additional methods that could provide an equivalent or 
greater level of safety. Therefore, PHMSA proposed to allow the 
following six methods for MAOP reconfirmation, including the 
conventional pressure test method.
Summary of PHMSA's Proposal: Method 1--Pressure Test
    A pressure test is the most conventional assessment method by which 
an operator may reconfirm a pipeline segment's MAOP. PHMSA proposed 
standards for conducting pressure tests for MAOP reconfirmation in part 
to meet the intent of NTSB recommendations P-11-14 and P-11-15. First, 
PHMSA proposed minimum test pressure standards where a pipeline 
segment's MAOP would be equal to the test pressure divided by the 
greater of either 1.25 or the applicable class location factor. Second, 
if the pipeline segment might be susceptible to cracks or crack-like 
defects,\68\ then the operator must incorporate a spike pressure 
feature into the pressure test procedure. PHMSA proposed standards for 
the spike hydrostatic test in Sec.  192.506. If the operator has reason 
to believe any pipeline segment may be susceptible to cracks or crack-
like defects, the operator would be required to also estimate the 
remaining life of the pipeline in accordance with the same standards 
specified in Method 3, the engineering critical assessment method.
---------------------------------------------------------------------------

    \68\ These pipelines can include pipelines constructed with 
``legacy pipe'' or using ``legacy construction techniques;'' 
pipelines with evidence or risk of stress corrosion cracking or 
girth weld cracks; or pipelines that have experienced an incident 
due to an original manufacturing-related defects, construction-
related defects, installation-related defects, or fabrication-
related defects.
---------------------------------------------------------------------------

Summary of Public Comment: Method 1--Pressure Test
    Several commenters opposed the proposed provisions requiring a 
spike test to be conducted as part of the pressure test for the 
purposes of MAOP reconfirmation, and these comments are discussed 
further under the ``spike test'' portion of the proposal and comment 
summary of this rulemaking.
    API suggested that a pipeline segment's MAOP can be best 
established through performing a combination of pressure tests and ILI 
examinations, and they discussed how operators could conduct 
hydrostatic pressure testing to determine the in-place yield strength 
of a segment of pipeline by conducting a ``spike'' test pressure held 
for a few minutes followed by a subpart J pressure test approximately 
10 percent below the spike level. API further stated that using ILI 
tools in conjunction with this method would further substantiate the 
results, as geometry ILI tools capable of measuring inside diameter to 
detect yielding could further substantiate and quantify the results of 
the pressure test.
    AGA stated that while they believe that pressure testing is a 
straightforward and well-established method, the proposed Method 1 MAOP 
reconfirmation requirements are unnecessarily complex. AGA further 
stated that subpart J provides different requirements and 
specifications for pressure tests based on the type of pipe being 
tested, and that Method 1 should refer to subpart J rather than to 
Sec.  192.505(c) specifically, which requires unnecessarily stringent 
requirements. PG&E supported the proposed provisions and committed to 
pressure testing all pipes.
    INGAA stated that since the basic strength properties of steel pipe 
do not change over time, PHMSA should not limit allowable tests to only 
those conducted after July 1, 1965, as was proposed in Sec.  
192.619(a)(2)(ii). They emphasized that the test parameters, not

[[Page 52200]]

the test date, should be considered for MAOP reconfirmation. Further, 
INGAA stated that recognizing the validity of earlier tests would not 
necessarily mean that no further pressure tests would be conducted, as 
periodic testing may be required to ensure the continued integrity of 
the pipeline segment under the operator's integrity management program. 
However, such additional tests are managed under IM, which is separate 
from MAOP reconfirmation.
    Certain commenters stated that a spike test is not required to 
establish an adequate margin of safety for MAOP reconfirmation and 
suggested PHMSA eliminate spike testing from the pressure test method 
of MAOP reconfirmation.
    Regarding the proposed definitions of ``legacy pipe'' and ``legacy 
construction,'' AGA and Xcel Energy commented that as proposed, the 
definitions could be interpreted to apply to distribution pipelines as 
well as gas transmission pipelines. Commenters requested that PHMSA 
explicitly exclude distribution pipelines from these definitions, which 
would be applicable to all part 192.
    On March 26, 2018, the GPAC recommended that PHMSA delete the spike 
test requirements from the pressure test method of MAOP reconfirmation. 
The GPAC also recommended that PHMSA require operators to perform a 
pressure test in accordance with subpart J of part 192 rather than 
refer to specific requirements in Sec.  192.505. Further, and as 
discussed during the meetings of December 2017 and March 26, 2018, if 
the applicable pressure test segment does not have traceable, 
verifiable, and complete MAOP records, the operator must use the best 
available information upon which the MAOP is currently based to conduct 
the pressure test. The GPAC recommended PHMSA create a requirement for 
the operator of such a pipeline segment to add the test segment to its 
plan for opportunistically verifying material properties in accordance 
with the material properties verification provisions. During the 
meeting, PHMSA noted that most pressure tests would present at least 
two opportunities for material properties verification at the test 
manifolds.
PHMSA Response: Method 1--Pressure Test
    PHMSA appreciates the information provided by the commenters 
regarding the pressure test method of MAOP reconfirmation (Method 1). 
After considering these comments and as recommended by the GPAC, PHMSA 
is eliminating the spike testing requirement as part of the pressure 
test method of MAOP reconfirmation. As commenters stated, spike testing 
is primarily used for the mitigation of cracks and crack-like defects, 
and PHMSA has determined it would therefore be more appropriate to be 
placed within the context of threat management under IM. Additionally, 
PHMSA is removing the definitions for and related references to 
``legacy pipe'' and ``legacy construction'' in this final rule because 
the applicability to pipe with ``legacy pipe or construction'' leaks or 
failures was dropped from the applicability criteria for MAOP 
reconfirmation. PHMSA also modified the rule to refer to subpart J 
pressure tests rather than paragraph Sec.  192.505(c), specifically, 
and to recognize the validity of earlier pressure tests. Lastly, if an 
operator does not have traceable, verifiable, and complete records for 
the material properties needed to establish MAOP by pressure testing, 
PHMSA is requiring that operators test, in accordance with the material 
verification requirements, the pipe materials cut out from the test 
manifold sites at the time the pressure test is conducted. Further, if 
there is a failure during the pressure test, the operator must test any 
removed pipe from the pressure test failure in accordance with the 
material properties verification requirements to ensure that the 
segment of pipe is consistent with operator's sampling program 
established under Sec.  192.607. This will avoid issues where operators 
may not have the documented and verified physical pipeline material 
properties and attributes that would otherwise be necessary to perform 
a hydrostatic pressure test to reconfirm MAOP.
Summary of Proposal: Method 2--Pressure Reduction
    In the NPRM, PHMSA proposed that pipeline operators could choose to 
reduce the MAOP of the applicable pipeline segment to reconfirm the 
segment's MAOP. This approach would use the recent operating pressure 
as a de facto pressure test, and then an operator would set the 
pipeline segment's MAOP at a slightly lower pressure. PHMSA proposed 
that operators using this method set the pipeline's MAOP to no greater 
than the highest actual operating pressure sustained by the pipeline 
during the 18 months preceding the effective date of the final rule 
divided by the greater of either 1.25 or the applicable class location, 
which are the same safety factors as used for the pressure testing in 
Method 1. PHMSA included standards for establishing the highest actual 
sustained pressure for the purposes of reconfirming MAOP under this 
method and included standards for addressing class location changes. 
Additionally, PHMSA proposed that, if the operator has reason to 
believe any pipeline segment contains or may be susceptible to cracks 
or crack-like defects, the operator would be required to estimate the 
remaining life of the pipeline.
Summary of Public Comment: Method 2--Pressure Reduction
    AGA commented that the 18-month look-back time frame listed in the 
pressure reduction MAOP reconfirmation method is a much too narrow time 
frame for consideration and that the section should be rewritten to 
clarify that the pressure reduction should be taken from either (1) the 
immediate past 18 months, or (2) 5 years from the time the last 
pressure reduction was taken, stating that tying the baseline pressure 
to the effective date of the rule is arbitrary. Enterprise Products 
recommended that PHMSA clarify the derating criteria used for pipes 
that use this method of reconfirming MAOP. Further, Piedmont expressed 
concern that this method does not account for the actual gap that can 
occur between MAOP and operating pressure. Some commenters questioned 
whether the MAOP from which to take a pressure reduction was based on 
the most recent pressure test or the historical highest-pressure test, 
and some commenters suggested PHMSA revise this provision to allow 
operators to reconfirm the MAOP based on the existing MAOP and not 
using an 18-month look-back period unless an incident caused by a 
material-related or construction-related defect has occurred on the 
pipeline since its last subpart J pressure test.
    TPA stated that using this method unfairly penalizes operators in 
situations where the operator has prepared for future needs and has not 
operated at MAOP for a period greater than 18 months. Similarly, 
another commenter suggested that operators who have already reduced 
MAOP on pipeline segments to be proactive should not be penalized by 
having to take an additional reduction in MAOP.
    Some commenters recommended limiting the applicability of this 
method to those pipelines operating at 30 percent SMYS or greater.
    Regarding the pressure reduction method for MAOP reconfirmation, 
the GPAC recommended PHMSA increase the look-back period from 18 months 
to 5 years and remove the requirements for operators selecting to take 
the pressure reduction to reconfirm MAOP to

[[Page 52201]]

perform fracture mechanics analysis on those pipeline segments.
PHMSA Response: Method 2--Pressure Reduction
    PHMSA appreciates the information provided by the commenters 
regarding the pressure reduction method of MAOP reconfirmation (Method 
2). After considering these comments and as recommended by the GPAC, 
PHMSA is increasing the look-back period to 5 years from the 
publication date of the rule and is removing the requirements for 
operators to perform fracture mechanics analysis on those pipeline 
segments where the operator has selected Method 2. PHMSA made this 
change because the 5-year look-back period is consistent with IM 
requirements regarding MAOP confirmation.
Summary of PHMSA's Proposal: Method 3--Engineering Critical Assessment
    Method 3 directly addresses the congressional mandate for PHMSA to 
consider safety testing methodologies that include other alternative 
methods, including ILI, determined to be of equal or greater 
effectiveness. Demonstrating that knowledge gained from an ILI 
assessment provides an equivalent level of safety as a pressure test is 
technically challenging. PHMSA used best safety practices gained from 
implementation of integrity management since 2003; development of class 
location special permits; and technical research on related topics, 
such as analysis of crack defects and seam defects. PHMSA applied these 
principles and analytical methods to develop an engineering critical 
assessment (ECA) methodology, which applies state-of-the-art fracture 
mechanics analysis to analyze defects in the pipe and determine if 
those defects would or would not survive a hydrostatic pressure test at 
the test pressure needed to establish MAOP. In addition, PHMSA proposed 
that if the operator has reason to believe any pipeline segment 
contains or may be susceptible to cracks or crack-like defects, the 
operator would be required to estimate the remaining life of the 
pipeline using the fracture mechanics standards PHMSA specified.
Summary of Public Comment: Method 3--Engineering Critical Assessment
    Several trade associations and pipeline industry entities stated 
that ILI is the best and most practical method for MAOP reconfirmation 
due to its cost-effectiveness and environmentally friendly nature, and 
that PHMSA should allow operators to use ILI as a reconfirmation 
method. These commenters, however, also stated that the requirements 
proposed for the usage of ILI with an ECA are overly complicated and 
burdensome, and they specifically recommended that the final rule 
should be simplified so that this method will play a greater role in 
MAOP reconfirmation in lieu of a pressure test. For example, INGAA 
asserted that PHMSA should remove the requirements in the ECA related 
to operations, maintenance, and integrity management, arguing that 
these requirements do not factor into MAOP reconfirmation and would be 
covered elsewhere in part 192. Further, INGAA proposed additional 
alternatives for using the ECA method to obtain necessary data for MAOP 
reconfirmation, asserting that these alternatives would be less 
burdensome and equally effective. More specifically, INGAA suggested 
removing duplicate regulatory language, removing the pre-approval 
process for ILI, and adding unity plots as a method for operators to 
demonstrate that ILI is reliable for identifying and sizing actionable 
anomalies. TransCanada and PECO Energy Co. stated that for the ECA 
method to be used by industry, the detailed requirements listed under 
this method in the proposed rule should be replaced with the use of 
standard ECA best practices.
    Some commenters suggested that operators have long relied on sound 
engineering judgments and conservative assumptions to account for 
record gaps. Commenters stated that, if stripped of the ability to use 
sound engineering judgment and conservative assumptions, operators 
would need to substantially invest in processes, procedures, tests, and 
project engineering and support to develop and implement a 
comprehensive material properties verification plan as outlined in the 
proposed regulations. Another commenter asked for clarification on 
using assumptions of Grade A pipe (30,000 psi) versus the use of 24,000 
psi as noted in Sec.  192.107(b)(2) if the SMYS or actual material 
yield strength and ultimate tensile strength is unknown or is not 
documented in traceable, verifiable, and complete records.
    Another commenter suggested that in cases where a pipeline has been 
pressure tested, but not to the level of 1.25 times MAOP, PHMSA should 
allow operators to augment the original test with an ECA and other 
analysis to reconfirm the pipeline segment's MAOP under method 3.
    The PST stated that there are certain cases in which the ECA method 
should not be allowed as an alternative to pressure testing. Citing a 
white paper prepared by Accufacts, Inc. on ECA methodology, the PST 
recommended that PHMSA prohibit the use of the ECA method for 
determining the strength of a pipeline segment in cases where there are 
girth weld crack threats, significant stress corrosion cracking 
threats, or dents with stress concentrator threats.
    During the GPAC meeting on March 27, 2018, the GPAC recommended 
that PHMSA remove the fracture mechanics analysis for failure stress 
and crack growth analysis requirements from the ECA method of MAOP 
reconfirmation and move them to a stand-alone section in the 
regulations. Further, the GPAC recommended that such a section should 
not specify when, or for which pipeline segments, fracture mechanics 
analysis would be required. The GPAC suggested that this new fracture 
mechanics section outline a procedure by which operators perform 
fracture mechanics analysis when required or allowed by other sections 
of part 192, which was similar to its treatment of the proposed 
material properties verification procedures at Sec.  192.607. Under the 
GPAC's proposal, the ECA method for MAOP reconfirmation would not 
contain any specific technical fracture mechanics requirements or 
Charpy V-notch toughness values but would instead refer to the new 
fracture mechanics section. Other recommendations related specifically 
to the new fracture mechanics section are discussed in that area of the 
proposal and comment summary section of this document.
    The GPAC also recommended PHMSA add a requirement to verify 
material properties in accordance with the rule's material properties 
verification provisions if the information needed to conduct a 
successful ECA is not documented in traceable, verifiable, and complete 
records.
PHMSA Response: Method 3--Engineering Critical Assessment
    PHMSA appreciates the information provided by the commenters 
regarding the ECA method of MAOP reconfirmation (Method 3). As 
recommended by the GPAC, PHMSA is removing the fracture mechanics 
analysis requirements from the ECA method of MAOP reconfirmation and 
moving them to a new stand-alone Sec.  192.712. PHMSA agrees this 
change will improve comprehension of the regulations. This new section 
does not specify when, or for which pipeline segments, fracture 
mechanics analysis would be required but instead outlines a procedure 
by which operators perform

[[Page 52202]]

fracture mechanics analysis when required by other sections of part 
192. Section 192.712 is referenced in the pressure reduction, ECA, and 
``other technology'' methods of MAOP reconfirmation under Sec.  
192.624, as well as in Sec.  192.917 for cyclic fatigue loading. 
Therefore, the ECA method for MAOP reconfirmation does not contain any 
specific technical fracture mechanics requirements or Charpy V-notch 
toughness values (full-size specimen, based on the lowest operational 
temperature) but instead refers to the new Sec.  192.712. Comments 
related to the assumptions an operator can use when material properties 
are unknown are addressed in the discussion on Sec.  192.712 below. 
PHMSA also added a requirement to verify material properties in 
accordance with the rule's material properties verification provisions 
at Sec.  192.607 if the information needed to conduct a successful ECA 
is not documented in traceable, verifiable, and complete records.
    PHMSA disagrees that the additional analytical requirements, beyond 
ILI, are overly complicated or burdensome. To conclude that an ECA is 
of equal or greater effectiveness as a pressure test for the purposes 
of MAOP reconfirmation, as mandated by Congress, more than an ILI and 
repair program is required. A pressure test proves that any flaws in 
the pipe are small enough to hold the test pressure without leaking. 
Such subcritical flaws must be analyzed to prove that they would pass a 
pressure test, even if the pressure test is not conducted. A fracture 
mechanics analysis is capable of reliably drawing such conclusions but 
must be carefully and capably performed. Such an analysis also requires 
accurate data. In the absence of reliable data for key parameters, such 
as fracture toughness, PHMSA allows the use of appropriately 
conservative assumptions. This is discussed in more detail in the 
sections below.
    Based on an ASME report and research sponsored by PHMSA,\69\ the 
ECA analysis can be reliably used to ascertain if a pipeline segment 
would pass a pressure test, even if it has seam weld cracking, and the 
final rule includes requirements for conducting ILI using tools capable 
of detecting girth weld cracks. The ECA must analyze any cracks or 
crack-like defects remaining in the pipe, or that could remain in the 
pipe, to determine the predicted failure pressure (PFP) of each defect.
---------------------------------------------------------------------------

    \69\ See: American Society of Mechanical Engineers (ASME) 
Standards Technology Report ``Integrity Management of Stress 
Corrosion Cracking in Gas Pipeline High Consequence Areas'' (STP-PT-
011), and ``Final Summary Report and Recommendations for the 
Comprehensive Study to Understand Longitudinal ERW Seam Failures--
Phase 1'' (Task 4.5); https://primis.phmsa.dot.gov/matrix/PrjHome.rdm?prj=390.
---------------------------------------------------------------------------

    PHMSA also notes that the final rule addresses cases where a 
pipeline has been pressure tested, but not to the level of 1.25 times 
MAOP, by allowing operators to account for those test results and 
augment the original test with an ECA, or conduct an ILI tool 
assessment program to characterize defects remaining in the pipe along 
with using an ECA to establish MAOP, to reconfirm the pipeline 
segment's MAOP using Method 3. Detailed ILI requirements are addressed 
in new Sec.  192.493, which is discussed in more detail below.
    PHMSA is moving the ECA process requirements in this final rule to 
a new stand-alone Sec.  192.632. Section 192.624(c)(3) (ECA method of 
MAOP reconfirmation) and the new Sec.  192.632 will cross-reference 
each other. PHMSA decided to make this change when finalizing this 
rulemaking only to improve the readability of the regulations. No 
substantive changes were made to the requirements in connection with 
this organizational change.
Summary of PHMSA's Proposal: Method 4--Pipe Replacement
    When reconfirming MAOP on certain pipeline segments, some operators 
may face significant technical challenges or costs when performing 
either a pressure test or an ILI examination, and it may be more 
economically viable to replace the pipeline. Therefore, PHMSA proposed 
to allow pipe replacement for operators to reconfirm their MAOP. In 
such cases, the replacement pipeline would be designed, constructed, 
and pressure tested according to current standards to establish MAOP.
Summary of Public Comment: Method 4--Pipe Replacement
    Commenters, including Mid-American Energy Company and Paiute 
Pipeline, stated their support for this method. The GPAC similarly 
supported this method and did not recommend any changes for this aspect 
of MAOP reconfirmation.
PHMSA Response: Method 4--Pipe Replacement
    PHMSA appreciates the information provided by the commenters 
regarding the pipe replacement method of MAOP reconfirmation (Method 
4). After considering these comments and as recommended by the GPAC, 
PHMSA is retaining the proposed rule text for Method 4 in the final 
rule.
Summary of PHMSA's Proposal: Method 5--Pressure Reduction for Small, 
Low-Pressure Pipelines
    For low-pressure, smaller-diameter pipeline segments with small 
potential impact radii (PIR), PHMSA proposed an MAOP reconfirmation 
method similar to the pressure reduction under Method 2. Operators of 
pipeline segments for which (1) the MAOP is less than 30 percent SMYS, 
(2) the PIR is less than or equal to 150 feet, (3) the nominal diameter 
is equal to or less than 8 inches,\70\ and (4) which cannot be assessed 
using ILI or a pressure test, may reconfirm the MAOP as the highest 
actual operating pressure sustained by the pipeline segment 18 months 
preceding the effective date of the final rule, divided by 1.1. In 
addition to this pressure reduction, operators of these lines would be 
required to perform external corrosion direct assessments in accordance 
with the IM provisions, develop and implement procedures to evaluate 
and mitigate any cracking defects, conduct a specified number of line 
patrols at certain intervals, conduct periodic leak surveys, and 
odorize the gas transported in the pipeline segment.
---------------------------------------------------------------------------

    \70\ 8.625 inches actual diameter.
---------------------------------------------------------------------------

Summary of Public Comment: Method 5--Pressure Reduction for Small, Low-
Pressure Pipelines
    AGA stated that PHMSA did not provide enough justification for 
imposing the additional pressure reduction requirements listed under 
this method, asserting that this method should require either a 10 
percent pressure reduction or the implementation of additional 
preventative actions that are feasible and practical, but not both. TPA 
stated that the 18-month criterion penalizes operators who may have 
operated pipelines at lower capacities to anticipate future needs. 
Furthermore, TPA urged PHMSA to limit the requirements for MAOP 
reconfirmation under Method 5 to the reduction in MAOP and not impose 
additional safety requirements, stating that these pipelines are 
generally considered low-stress pipelines and that their risk of 
rupture is very low. Similarly, API stated that the proposed 
requirements for odorization and frequent instrumented leak surveys are 
impractical. Some commenters felt that the terms for small potential 
impact radius and the applicable diameters should be defined.

[[Page 52203]]

    On March 27, 2018, the GPAC recommended PHMSA delete the size and 
pressure criteria of this method and base the applicability solely on a 
potential impact radius of less than or equal to 150 feet. The GPAC 
also recommended increasing the look-back period to 5 years from 18 
months. Further, the GPAC recommended PHMSA strike the additional 
requirements in this method related to external corrosion direct 
assessment, crack analysis, gas odorization, and fracture mechanics 
analysis. They also recommended PHMSA change the frequency of patrols 
and surveys to 4 times a year for Class 1 and Class 2 locations, and 6 
times per year for Class 3 and Class 4 locations.
PHMSA Response: Method 5--Pressure Reduction for Small, Low-Pressure 
Pipelines
    PHMSA appreciates the information provided by the commenters 
regarding the pressure reduction method of MAOP reconfirmation for 
small, low-pressure pipelines (Method 5). After considering these 
comments and as recommended by the GPAC, PHMSA is deleting the pipeline 
segment size and pressure criteria of this method and basing the 
applicability solely on a potential impact radius of less than or equal 
to 150 feet. PHMSA believes this change streamlines the regulations 
while maintaining pipeline safety. PHMSA is increasing the look-back 
period to 5 years, which is consistent with other sections of part 192, 
including integrity management. Additionally, PHMSA is deleting the 
requirements in this method related to external corrosion direct 
assessment, crack analysis, gas odorization, and fracture mechanics 
analysis. PHMSA is also changing the frequency of patrols and surveys 
to 4 times a year for Class 1 and Class 2 locations, and 6 times per 
year for Class 3 and Class 4 locations. PHMSA believes these changes 
increase regulatory flexibility while maintaining pipeline safety.
Summary of Proposal: Method 6--Alternative Technology
    PHMSA proposed that operators may use an alternative technical 
evaluation process that provides a documented engineering analysis for 
the purposes of MAOP reconfirmation. If an operator elects to use an 
alternative method for MAOP reconfirmation, it would have to notify 
PHMSA and provide a detailed fracture mechanics analysis--including the 
safety factors--to justify the establishment of the MAOP using the 
proposed alternative method. The notification would have to demonstrate 
that the proposed alternative method would provide an equivalent or 
greater level of safety than a pressure test. PHMSA included this 
option to allow and encourage the continual research and development 
needed to improve state-of-the-art fracture mechanics analysis, 
integrity assessment methods, advances in metallurgical engineering, 
and new techniques.
Summary of Public Comment: Method 6--Alternative Technology
    For the alternative technologies method of MAOP reconfirmation, 
several stakeholders opposed the timeframes, case-by-case approval 
process, and procedural barriers PHMSA proposed for using this method. 
Several commenters, including Cheniere Energy, Delmarva Power & Light, 
and INGAA, suggested that the procedural hurdles required by the 
proposed provisions would make this option difficult for operators to 
use for MAOP reconfirmation as well as for any other provisions PHMSA 
allows alternative technology use with notification. More specifically, 
these commenters suggested that a process whereby PHMSA could object to 
the use of an alternative technology at any time during a project's 
lifecycle does not provide the level of certainty necessary for 
operators to move forward with using alternative technologies. That 
uncertainty would deter the development of what could be better or 
safer alternatives.
    Piedmont stated that it does not believe that the role of PHMSA 
includes determining the appropriate technologies to be used to 
reconfirm MAOP. Piedmont further stated that currently under subpart O, 
operators are required to obtain approval from PHMSA to use alternative 
technologies for integrity assessment, and that operators have waited 
more than 180 days for PHMSA to respond to these requests. Piedmont 
stated that this uncertainty cannot be reconciled with the planning and 
business considerations that an operator must consider when evaluating 
how to invest in technology and which methods to use for establishing 
MAOP. The PST stated that the approval process should be similar to the 
process used for special permits and that before these methods are 
approved by PHMSA, they should be subject to public review and comment 
under the National Environmental Policy Act of 1969 (NEPA).
    At the meeting on March 27, 2018, the GPAC recommended PHMSA 
incorporate the 90-day notification and objection procedure for the use 
of alternative technology. To summarize, operators would have to notify 
PHMSA of its intent to use other technology, and PHMSA would have 90 
days to respond with an objection if PHMSA had one, or a need for more 
review time. Otherwise, the operator would be free to use the proposed 
method or technology.
PHMSA Response: Method 6--Alternative Technology
    PHMSA appreciates the information provided by the commenters 
regarding the other technology method of MAOP reconfirmation (Method 
6). After considering these comments and as recommended by the GPAC, 
PHMSA is modifying the rule to incorporate the 90-day notification and 
objection procedure the committee recommended. Operators would have to 
notify PHMSA of its intent to use other technology to reconfirm MAOP in 
accordance with Sec.  192.18, and PHMSA would have 90 days to respond 
with an objection if PHMSA had one or a notice that PHMSA required more 
time for its review, which would extend the timeframe. Without a notice 
of objection or additional review by PHMSA, the operator would be 
allowed to use the alternative technology. PHMSA has successfully 
applied the notification process to other technology assessments under 
subpart O since its inception and does not believe a special permit 
process is warranted for every notification for alternative technology. 
PHMSA believes the changes made in the final rule will address the 
concerns about timeliness of notification reviews by PHMSA.

B. MAOP Reconfirmation--Sec.  192.624

iii.--Spike Test

1. Summary of PHMSA's Proposal
    The ``spike'' hydrostatic pressure test is a special feature of the 
pressure testing method of MAOP reconfirmation. PHMSA intends this 
aspect of the MAOP reconfirmation process to address the intent of NTSB 
recommendations P-11-14 (related to spike testing for grandfathered 
pipe) and P-11-15 (related to pressure testing to show that 
manufacturing and construction-related defects are stable).
    PHMSA proposed that a spike test would be required for cases where 
a pipeline segment might be susceptible to cracks or crack-like 
defects. Such pipe may include ``legacy pipe;'' pipe constructed using 
``legacy'' construction techniques; pipelines that have experienced an 
incident due to an original manufacturing-related defect, a 
construction-, installation-, or fabrication-related defect; or pipe 
with

[[Page 52204]]

stress corrosion cracking or girth weld cracks. Cracks and crack-like 
defects in some cases may be susceptible to a phenomenon called 
``pressure reversal,'' which is the failure of a defect at a pressure 
less than a pressure level that the flaw has previously experienced and 
survived. The increased stress from the test pressure may cause latent 
cracks that are almost, but not quite, large enough to fail to grow 
during the test. If the crack does not fail before the test is 
completed, the resultant crack that remains in the pipe may be large 
enough to no longer be able to pass another pressure test. The spike 
portion of the pressure test is designed to cause such marginal crack 
defects to fail during the early, spike phase of the pressure test. The 
post-spike, long-duration test pressure validates the operational 
strength of the pipe. Using a short-duration, very high spike pressure 
followed by a long-duration integrity verification pressure provides 
greater assurance that the test is not ``growing cracks'' that could 
fail in-service after the test is completed. PHMSA proposed standards 
for the spike hydrostatic test in Sec.  192.506. PHMSA used several 
technical reports and studies, including PHMSA-sponsored research, to 
inform the standards proposed for the spike test. Those materials 
include, American Society of Mechanical Engineers Standards Technology 
Report ``Integrity Management of Stress Corrosion Cracking in Gas 
Pipeline High Consequence Areas'' (STP-PT-011), and ``Final Summary 
Report and Recommendations for the Comprehensive Study to Understand 
Longitudinal ERW Seam Failures--Phase 1'' (Task 4.5).\71\
---------------------------------------------------------------------------

    \71\ https://primis.phmsa.dot.gov/matrix/PrjHome.rdm?prj=390.
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2. Summary of Public Comment
    Some commenters supported the concept of requiring the use of a 
spike hydrostatic pressure test as part of the MAOP reconfirmation 
process for establishing MAOP but expressed concern over specific 
aspects of the provision. For example, AGA urged PHMSA to allow 
pneumatic pressure tests as well as hydrostatic pressure tests. In 
addition, AGA disagreed with the allotted test duration provided in the 
proposal. Similarly, other operators who commented, such as CenterPoint 
Energy and Dominion East Ohio, stated that the proposed spike test 
target hold pressure of 30 minutes exceeds the time needed to determine 
the mechanical integrity of the pipeline test segment and will cause 
pre-existing crack-like defects to grow. Alternatively, Dominion 
Transmission, Tallgrass Energy Partners, SoCalGas, and Paiute Pipelines 
stated that a test level of 100 percent SMYS, not 105 percent SMYS, 
would be sufficient to remediate cracking threats. Enterprise Products 
stated that the requirements for the design of a spike test should be 
based on integrity science, such as fatigue life and reassessment 
intervals, and suggested PHMSA's proposed spike test pressure limits 
were set at an arbitrary level. Enterprise further stated that the 
utility of stressing a pipe beyond 100 percent of its yield strength is 
questionable and potentially damages the pipe. Other commenters, 
including MidAmerican Energy Co., requested that pneumatic spike tests 
to 1.5 times MAOP be allowed when the resultant pressure complies with 
the limitations stated in the table in Sec.  192.503(c).
    Trade associations and pipeline industry entities, including INGAA, 
GPA, and TPA, asserted that PHMSA should eliminate the spike test 
requirement for establishing MAOP entirely. These commenters stated 
that the proposed provisions went beyond what was required to reconfirm 
MAOP for an accepted margin of safety. These commenters further 
asserted that spike testing is not an appropriate technique for MAOP 
reconfirmation, and it could result in unintended negative consequences 
without improving pipeline safety. They stated that spike testing is an 
aggressive and destructive technique that should be used only in cases 
in which time-dependent threats, such as a significant risk of stress 
corrosion cracking, exist.
    INGAA and other commenters agreed with PHMSA that the use of spike 
hydrostatic testing is appropriate for time-dependent threats, such as 
stress corrosion cracking. INGAA, however, suggested changes to the 
proposed spike hydrostatic pressure test provisions and the cross-
reference to those provisions in the proposed IM assessment method 
revisions to limit the spike testing requirement to time-dependent 
threats, to test to a minimum of 100 percent SMYS instead of 105 
percent, and to provide an alternative for use of an instrumented leak 
survey. INGAA agreed that spike testing is the best means of testing a 
pipeline with a history of environmental cracking, such as stress 
corrosion cracking that has developed while a pipeline is in service, 
and noted that a spike test may be of value for in-service pipelines 
where metallurgical fatigue is of concern. INGAA further stated that 
pressure cycling should not need to be included in the proposed spike 
test provisions and that PHMSA should amend the proposed rule to limit 
spike testing only to those pipeline segments with stress corrosion 
cracking.
    An additional commenter suggested PHMSA should allow operators to 
use the short-duration spike portion of a spike pressure test to 
determine the lower bound of the yield strength of the test section, 
including all pipe and components that are subjected to the test 
pressure. Such a test, if used for this purpose, must also confirm that 
yielding beyond that experienced in a standard tensile test to 
determine yield strength, typically on the order of 0.5 percent, has 
not occurred. This confirmation may be demonstrated by data from a 
pressure-volume plot of the test or a post-test geometry tool in-line 
inspection.
    Public interest and other groups, including Pipeline Safety 
Coalition, Environmental Defense Fund (EDF), and NAPSR, expressed 
support for spike testing, stating that it would provide for increased 
pipeline safety. NAPSR further stated that the option of applying to 
use alternative technology or an alternative technological evaluation 
process would allow for some flexibility in cases in which a 
hydrostatic test is impractical. EDF also suggested additional measures 
to mitigate emissions from methane gas lost during testing.
    At the GPAC meeting on March 2, 2018, the GPAC recommended that 
PHMSA revise the spike test requirements to change the minimum spike 
pressure to the lesser of 100 percent SMYS or 1.5 times MAOP, reduce 
the spike hold time to a minimum of 15 minutes after the spike pressure 
stabilizes, revise the applicable language to refer specifically to 
``time-dependent'' cracking, incorporate the 90-day notification and 
objection procedure discussed for other sections, and adjust the SME 
requirements by adding language describing a ``qualified technical 
subject matter expert'' where applicable.
3. PHMSA Response
    PHMSA appreciates the information provided by the commenters 
regarding the requirements for spike pressure testing. After 
considering these comments and as recommended by the GPAC, PHMSA is 
modifying the rule to change the minimum spike pressure to the lesser 
of 100 percent SMYS or 1.5 times MAOP, as PHMSA believes these 
pressures are sufficient to maintain pipeline safety. PHMSA is 
specifying a spike hold time of a minimum of 15 minutes after the spike 
pressure stabilizes, rather than a 30-minute overall hold time, to be 
consistent with pipeline safety. Additionally, PHMSA is

[[Page 52205]]

modifying the rule to revise the applicable language to refer 
specifically to ``time-dependent'' cracking, incorporate the same 
notification procedure under Sec.  192.18 with the 90-day timeframe for 
objections or requests for more review time, and adjust the SME 
requirements by using broader language describing a ``qualified 
technical subject matter expert'' where applicable instead of 
specifying technical fields of expertise such as metallurgy or fracture 
mechanics. PHMSA believes these changes increase regulatory flexibility 
while maintaining pipeline safety.
    In addition, as stated above, the spike test is being removed from 
the MAOP reconfirmation requirements. The spike test procedure in the 
new Sec.  192.506 would be used whenever required by other requirements 
in part 192 to address crack remediation and the integrity threat of 
cracks and crack-like defects.
    PHMSA disagrees with allowing pneumatic spike tests to 1.5 times 
MAOP based on safety concerns. Pneumatic pressure tests are allowed in 
Sec.  192.503(c), with certain limitations, for new, relocated, or 
replaced pipe. For new, relocated, or replaced pipe, there is knowledge 
that the pipe is likely sound and is usually manufactured with recent 
mill pressure tests to confirm the pipe meets applicable standards. A 
spike test to perform an integrity assessment on in-situ pipe with 
known or suspected cracks or crack-like defects presents a much higher 
likelihood of the pipeline segment experiencing a leak or rupture 
during the test with resultant consequences, including the possibility 
of fire or explosion. PHMSA notes that conducting a pneumatic test 
using a compressible gas, such as air, nitrogen, or methane, would be a 
safety concern for the public and operating personnel. Gas that is 
highly compressed has stored energy that would be suddenly released 
should there be a flaw in the pipe. Liquids, such as water, do not have 
the stored energy release that a compressible gas has should the pipe 
have a flaw that either leaks or ruptures. Therefore, the safety risk 
of performing a hydrostatic pressure test (with water) is much lower 
due to the less-compressible nature of liquids. Compressed gas would be 
a fire or explosion hazard to the public. However, as specified in the 
proposed and final rules, operators that desire to use a pneumatic 
spike test may propose using such a test, with justification, by 
submitting a notification to PHMSA.

B. MAOP Reconfirmation--Sec.  192.624

iv.--Fracture Mechanics

1. Summary of PHMSA's Proposal
    In the proposal, PHMSA determined that fracture mechanics analysis 
is a key aspect of meeting the congressional mandate to consider safety 
testing methodologies for MAOP reconfirmation of equal or greater 
effectiveness as a pressure test, including other alternative methods 
such as ILI. Demonstrating that knowledge gained from an ILI assessment 
provides an equivalent level of safety as a pressure test is 
technically challenging. An ILI assessment might reveal the presence of 
crack flaws and crack-like defects and characterize them within the 
accuracy of tool performance capabilities, but determining whether 
those cracks would survive a pressure test to reconfirm MAOP requires 
very in-depth and highly technical analysis. Such an analysis not only 
requires an accurate characterization of cracks, it also requires 
accurate and known metallurgical properties of the pipe. To address 
these aspects, PHMSA proposed more detailed requirements in Sec.  
192.921 for evaluating defects discovered during ILI to account for 
tool accuracy and other factors to accurately characterize flaw 
dimensions and support accurate fracture mechanics analysis. In 
addition, the material properties verification and documentation 
requirements PHMSA proposed are critical to performing fracture 
mechanics analysis of ILI-discovered defects that would be accurate 
enough to establish MAOP in a way that is demonstrably equivalent in 
safety to a pressure test. In the MAOP reconfirmation provisions, PHMSA 
proposed new requirements for fracture mechanics analysis for failure 
stress and cracks, listing specific requirements, standards, and data 
operators must use when performing a fracture mechanics analysis.
2. Summary of Public Comment
    Most industry stakeholders were opposed to the proposed fracture 
mechanics requirements. AGA, New Mexico Gas Co., and TPA suggested that 
fracture mechanics have a limited place in preventing pipeline failures 
or predicting them accurately and should not be a component of MAOP 
reconfirmation. AGA stated that the rule should not prescriptively 
require fracture mechanics calculations to be performed for a broad 
range of applications but should be narrowed to include only 
transmission pipelines operating at a hoop stress greater than 30 
percent SMYS, given that pipelines that operate below 30 percent SMYS 
have a strong tendency to leak rather than rupture.
    Commenters also stated that requiring fracture mechanics as any 
part of the MAOP reconfirmation process was overly burdensome and 
unclear. Specifically, API stated that some of the requirements listed 
under the MAOP reconfirmation requirements were overly conservative and 
burdensome for most situations where this technique would be used. For 
instance, a commenter noted that there is no non-destructive evaluation 
(NDE) methodology for obtaining Charpy V-notch toughness values. 
Therefore, PHMSA's requirement to obtain Charpy V-notch toughness 
values eliminates the availability of non-destructive testing. Further, 
a commenter noted that the proposed ECA analysis prescribed a body 
toughness of 5-ft.-lbs. and a seam toughness of 1-ft.-lbs., which are 
arbitrary and very conservative. Vintage pipelines will not have Charpy 
V-notch toughness data, and requiring an overly conservative assumption 
of toughness is not reasonable. Toughness can vary depending on the 
manufacturer, the manufacturing method, and the pipe vintage, and it 
should not be prescribed in the regulations. The commenter further 
noted that using the conservative defaults, especially the overly 
conservative defaults PHMSA proposed, may result in an unacceptably 
short remaining life of the pipeline.
    Similarly, commenters recommended PHMSA allow alternative methods 
of assessing strength properties that provide a suitable lower bound to 
the actual strengths. Allowing alternative methods will provide 
flexibility to consider conservative, but realistic, estimates of 
material properties. Commenters also stated that SMEs in both 
metallurgy and fracture mechanics are not needed to validate non-
destructive test (NDT) methods. Engineers with knowledge in test 
validation methods but not necessarily metallurgy and fracture 
mechanics are capable of validating NDT methods.
    More broadly, Energy Transfer Partners suggested that the proposed 
language for fracture mechanics is misplaced in MAOP reconfirmation and 
should be moved to the proposed requirements for non-HCA assessments, 
or elsewhere, since this text more closely resembles an ``assessment.'' 
Other commenters agreed with that concept, suggesting fracture 
mechanics is more appropriate under the IM measures for threat 
mitigation rather than for MAOP reconfirmation.
    As previously discussed in this document, the GPAC recommended

[[Page 52206]]

PHMSA move the fracture mechanics analysis requirements out of the ECA 
method of MAOP reconfirmation and into a new stand-alone section in the 
regulations, making it a process for performing fracture mechanics 
analysis whenever required or allowed by part 192. The committee 
therefore recommended that PHMSA delete any cross-references to the 
MAOP reconfirmation and the spike pressure test provisions. The GPAC 
also recommended that operators make and retain specific records to 
document fracture mechanics analyses performed.
    Along with moving the fracture mechanics analysis requirements to a 
stand-alone section, the GPAC had several specific recommendations 
related to how the requirements would function. The GPAC recommended 
PHMSA remove ILI tool performance specifications and replace them with 
a requirement for operators to verify tool performance using unity 
plots or equivalent technologies, and also recommended revisions to the 
fracture mechanics requirements by striking the sensitivity analysis 
requirements and replacing them with a requirement for operators to 
account for model inaccuracies and tolerances.
    As it pertains to the Charpy V-notch toughness values (full-size 
specimen, based on the lowest operational temperatures) used in 
fracture mechanics analysis, the GPAC recommended that operators could 
use a conservative Charpy V-notch toughness value based on the sampling 
requirements of the material properties verification provisions or use 
Charpy V-notch toughness values from similar-vintage pipe until the 
actual properties are obtained through the operator's opportunistic 
testing program. The GPAC recommended that PHMSA clarify that default 
Charpy V-notch toughness values of 13-ft.-lbs. for pipe body and 4-ft.-
lbs. for pipe seam only apply to pipe with suspected low-toughness 
properties or unknown toughness properties. Further, if a pipeline 
segment has a history of leaks or failures due to cracks, the GPAC 
recommended PHMSA require the operator to work diligently to obtain any 
unknown toughness data. In the interim, operators of such pipeline 
segments must use Charpy V-notch toughness values of 5-ft.-lbs. for 
pipe body and 1-ft.-lbs. for pipe seam. The GPAC also recommended PHMSA 
include a 90-day notification procedure similar to the previously 
agreed-upon procedure if operators wanted to request the use of 
differing Charpy V-notch toughness values.
3. PHMSA Response
    PHMSA appreciates the information provided by the commenters 
regarding the proposed fracture mechanics requirements. After 
considering these comments and as recommended by the GPAC, PHMSA is 
moving the fracture mechanics analysis requirements out of the ECA 
method of MAOP reconfirmation and into a new stand-alone Sec.  192.712 
in the regulations, making it a process by which operators must perform 
fracture mechanics analysis whenever required by part 192. This change 
was made to increase the readability of the regulations. As a part of 
making these provisions into a stand-alone section in the regulations, 
PHMSA is also deleting the references within Sec.  192.712 to the MAOP 
reconfirmation and the spike pressure test provisions. PHMSA is adding 
a requirement for operators to make and retain specific records 
documenting any fracture mechanics analyses performed. PHMSA is also 
removing ILI tool performance specifications and sensitivity analysis 
requirements and replacing them with a requirement for operators to 
verify tool performance using unity plots or equivalent technologies 
and to account for model inaccuracies and tolerances. This change will 
increase regulatory flexibility while maintaining pipeline safety.
    Regarding the default Charpy V-notch toughness values (full-size 
specimen, based on the lowest operational temperatures) used in 
fracture mechanics analysis when actual values are not known, industry 
and the GPAC had significant comments. PHMSA is aware of pipe 
manufactured per API Specification 5L in this decade (2010-2019) with 
Charpy V-notch toughness values for the weld seam as low as 1-ft. lbs. 
that has been used in gas transmission pipelines. Furthermore, API 5L 
does not contain required minimum Charpy V-notch toughness values for 
the weld seam.
    A single default assumed toughness value might be inappropriate or 
overly conservative under some circumstances, or it might be a proper 
choice under other circumstances. To address this issue in this final 
rule, PHMSA is allowing the use of: (1) Charpy V-notch toughness values 
(full-size specimen, based on the lowest operational temperatures) from 
the same vintage and the same steel pipe manufacturers with known 
properties; (2) a conservative Charpy V-notch toughness value to 
determine the toughness based upon the ongoing material properties 
verification process specified in Sec.  192.607; (3) maximum Charpy V-
notch toughness values of 13.0 ft.-lbs. for body cracks and 4.0 ft.-
lbs. for cold weld, lack of fusion, and selective seam weld corrosion 
defects if the pipeline segment does not have a history of reportable 
incidents caused by cracking or crack-like defects; (4) maximum Charpy 
V-notch toughness values of 5.0 ft.-lbs. for body cracks and 1.0 ft.-
lbs. for cold weld, lack of fusion, and selective seam weld corrosion 
if the pipeline segment has a history of reportable incidents caused by 
cracking or crack-like defects; or (5) other appropriate Charpy V-notch 
toughness values that an operator demonstrates can provide conservative 
Charpy V-notch toughness values for the analysis of the crack-related 
conditions of the line pipe upon submittal of a notification to PHMSA. 
These modifications will provide flexibility to operators for 
considering conservative but realistic estimates of material 
properties.
    PHMSA is also clarifying that operators do not need to use distinct 
metallurgy and fracture mechanics subject matter experts to review 
fracture mechanics analyses. In this final rule, PHMSA is replacing 
that requirement with a general requirement stating that fracture 
mechanics analyses must be reviewed and confirmed by a qualified 
subject matter expert. PHMSA expects a qualified subject matter expert 
to be an individual with formal or on-the-job technical training in the 
technical or operational area being analyzed, evaluated, or assessed. 
The operator must be able to document that the individual is 
appropriately knowledgeable and experienced in the subject being 
assessed.

B. MAOP Reconfirmation--Sec.  192.624

v.--Legacy Construction Techniques/Legacy Pipe

1. Summary of PHMSA's Proposal
    PHMSA proposed to add a definition to part 192 for ``legacy 
construction techniques,'' which defined historical practices used to 
construct or repair transmission pipeline segments that are no longer 
recognized as acceptable. In addition, PHMSA proposed a definition for 
``legacy pipe'' that is defined by the presence of specific legacy 
manufacturing, welding, and joining techniques.
2. Summary of Public Comment
    AGA expressed significant concerns with the proposed definitions of 
legacy pipe and legacy construction techniques for the purposes of part 
192, commenting that PHMSA should eliminate the use of the terms 
entirely or otherwise revise these definitions to

[[Page 52207]]

exclude currently acceptable manufacturing and construction techniques. 
AGA stated if PHMSA were to codify the definitions of legacy pipe and 
legacy construction techniques, then PHMSA should limit its catch-all 
provisions within the language of the definitions to pipes with a 
longitudinal joint factor of less than 1.0. Doing so would ultimately 
include pipes with unknown joint factors, as Sec.  192.113 requires a 
default longitudinal joint factor of 0.80 for any pipe with an unknown 
longitudinal joint factor. Similarly, AGL Resources, Alliant Energy, 
Atmos Energy, and TECO Peoples Gas supported AGA's suggested revisions 
to the definitions of legacy construction techniques and legacy pipe. 
API commented that PHMSA's proposed definition of legacy construction 
technique inappropriately includes the repair technique of puddle welds 
and recommended PHMSA clarify the definitions of wrought iron and pipe 
made from Bessemer steel. Dominion Transmission commented there may be 
instances where the longitudinal seam for modern day pipe is unknown, 
yet the pipe is not a high-risk seam type. They stated that such pipe 
does not present an integrity threat and should be excluded from the 
``legacy pipe'' definition.
    Gas Piping Technology Committee commented that the proposed 
definition of legacy construction techniques seems to contain some 
erroneous information. They asserted that the proposed definition went 
too far by implying that all the listed methods are no longer used to 
construct or repair pipelines, stating that while wrinkle bends may no 
longer be a common construction technique, they are still allowed under 
Sec.  192.315 for steel pipe operating at a pressure producing a hoop 
stress of less than 30 percent of SMYS. Similarly, Oleksa and 
Associates commented that some operators are still installing Dresser 
couplings.
    The Michigan Public Service Commission staff suggested that PHMSA 
add to the definition of ``legacy construction techniques'' a 
subsection that addresses other legacy construction techniques that are 
not in the current list and include within this subsection language 
referencing ``all other'' techniques. Northern Natural Gas proposed 
PHMSA eliminate the phrase ``including any of the following 
techniques'' from the definition of legacy construction techniques as 
it implies the list is not complete. They suggested that the definition 
of legacy pipe should differentiate between ductile and brittle pipe by 
toughness values in both the seam and the pipe body. Lastly, SoCalGas 
thought it would be more appropriate to reference these definitions 
under the IM regulations in subpart O instead of defining the terms in 
the context of the entire part.
    These definitions were taken up by the GPAC in the context of the 
scope of MAOP reconfirmation, and they recommended in the meeting on 
March 26, 2018, that the definitions be withdrawn. Because the GPAC 
recommended to revise the scope of MAOP confirmation to not include 
pipelines with previous reportable incidents due to crack defects, 
these definitions would no longer be needed in the rule.
3. PHMSA Response
    PHMSA appreciates the information provided by the commenters 
regarding the proposed definitions for ``legacy pipe'' and ``legacy 
construction techniques.'' After considering these comments and as 
recommended by the GPAC, PHMSA is withdrawing these definitions from 
the final rule. Because the revised scope of MAOP confirmation 
requirements, discussed in the previous sections, no longer includes 
pipelines with previous reportable incidents due to crack defects, 
these definitions are no longer necessary.

C. Seismicity and Other Integrity Management Clarifications--Sec.  
192.917

1. Summary of PHMSA's Proposal
    Subpart O of 49 CFR part 192 prescribes requirements for managing 
pipeline integrity in HCAs. It requires operators of covered segments 
to identify potential threats to pipeline integrity and use that threat 
identification in their integrity programs. Included within this 
process are requirements to identify threats to which the pipeline is 
susceptible, collect data for analysis, and perform a risk assessment. 
Special requirements are included to address particular threats such as 
third-party damage and manufacturing and construction defects.
    Following the PG&E incident, the NTSB recommended that PG&E 
evaluate every aspect of its IM program, paying particular attention to 
the areas identified in the incident investigation, and implement a 
revised IM program. PHMSA held a workshop on July 21, 2011, to address 
perceived shortcomings in the implementation of IM risk assessment 
processes and the information and data analysis (including records) 
upon which such risk assessments are based. PHMSA also sought input 
from stakeholders on these issues in the ANPRM.
    Section 29 of the 2011 Pipeline Safety Act requires that operators 
consider the seismicity of the geographic area in identifying and 
evaluating all potential threats to each pipeline segment, pursuant to 
49 CFR part 192. Pipeline threat analysis is addressed as one program 
element in the IM regulations in subpart O. Addressing seismicity is 
already implicitly required by Sec.  192.917 as part of addressing 
outside force threat through the incorporation by reference of ASME 
B31.8S. Based on the direction of the mandate, PHMSA proposed to 
explicitly require that operators analyze seismicity and related 
geotechnical hazards, such as geology and soil stability, as part of 
the threat identification IM program element and mitigate those threats 
of outside force damage. PHMSA determined this would clarify 
expectations for this requirement and explicitly implement section 29 
of the 2011 Pipeline Safety Act.
    PHMSA also proposed revisions to Sec.  192.917(e) to clarify that 
certain pipe designs must be pressure tested to assume that seam flaws 
are stable and that failures or changes to operating pressures that 
could affect seam stability are evaluated using fracture mechanics 
analysis.
2. Summary of Public Comment
    There was broad support for explicitly requiring the consideration 
of the seismicity of a geographic area when identifying and evaluating 
all potential threats to a pipeline segment, and several stakeholders 
suggested minor revisions to the proposal. California Public Utilities 
Commission (CPUC) supported the proposed provisions and recommended 
adding text that would require consideration of any significant 
localized threat that could affect the integrity of the pipeline. CPUC 
further commented that operating conditions on the pipeline must also 
be a factor when operators identify local threats.
    Some commenters, including PG&E and NGA, requested further 
clarification regarding what would constitute a seismic event for the 
purposes of identifying threats under the IM program for compliance 
purposes. AGA requested clarification on the requirements regarding 
whether operators are expected to conduct a one-time investigation on 
the risk of seismicity and geology, or if there is an expectation of a 
periodic requirement for re-investigation.
    Multiple commenters disagreed with the proposed requirement in 
Sec.  192.917(e) for operators to perform annual cyclic fatigue 
analyses if an operator identifies cyclic fatigue as a threat. INGAA 
and National Fuel

[[Page 52208]]

suggested that cyclic fatigue is an uncommon risk for natural gas 
pipelines and asserted that PHMSA did not provided significant 
technical justification for this analysis requirement. Some commenters 
suggested that the proposal to address cyclic fatigue and require 
pressure tests on seam threats is an overcompensation for the level of 
risk the threats present. Trade associations and pipeline industries 
proposed several alternative requirements for the conditions under 
which cyclic fatigue analyses should be required. API stated that they 
did not object to the measures listed, but the proposed provisions in 
Sec.  192.935(b)(2) imply that an operator must take all the actions 
listed. API asserted that PHMSA should modify this proposed provision 
to state that operators must consider taking the actions listed but 
would not be specifically required to take all of them. Other 
commenters expressed concern that these proposed requirements conflict 
with the proposed requirements for pipeline segments needing to 
undertake MAOP reconfirmation because they experienced an incident due 
to manufacturing and construction (M&C) defects. Specifically, the 
requirements under Sec.  192.917(e)(3) only allow operators to consider 
M&C defects stable if they have been subjected to a hydrostatic 
pressure test of 1.25 times MAOP, which would seemingly disallow or 
otherwise make fruitless the other methods of MAOP reconfirmation for 
these types of pipeline segments.
    At the GPAC meeting on January 12, 2017, the GPAC recommended that 
no changes should be made to the proposed provisions on seismicity.
    Regarding Sec.  192.917(e)(2), which was discussed during the 
meeting on June 6-7, 2017, the GPAC noted that, under this provision, 
operators should be monitoring for condition changes that would cause 
the threat to potentially activate, and those condition changes should 
be what triggers a reassessment. The GPAC also noted problems with a 
suggested revision of performing a cyclic fatigue analysis within a 7-
calendar-year period to match certain IM requirements because it would 
then impose a hard deadline on the continuous monitoring process and 
would prompt operators to act and again study cyclic fatigue even if 
the monitoring showed no evidence of cyclic fatigue being a threat. At 
the meeting, PHMSA suggested that operators could ensure the data 
involved in a cyclic fatigue analysis is periodically verified within a 
period not exceeding 7 years to align with IM requirements, but 
operators would only be required to perform a full evaluation if the 
data has changed. Following that discussion, the GPAC recommended 
revising the proposed requirements for cyclic fatigue at Sec.  192.917 
based on the discussion of GPAC members and considering PHMSA's 
proposed language that was presented at the meeting.
    At the GPAC meeting on March 26-28, 2018, a public commenter 
suggested PHMSA remove the word ``hydrostatic'' from the requirements 
for considering M&C-related defects stable because any strength test 
that is approved in subpart J should qualify. Further, that public 
commenter suggested adding language where a pressure reduction or an 
ILI assessment with an ECA could be allowed for M&C defects as well. 
Another public commenter suggested removing references to cracks in 
these sections if PHMSA was intending to create a new section dedicated 
to addressing crack defects.
    Ultimately, the GPAC recommended PHMSA revise the proposed 
requirements for M&C defects by deleting a cross-reference with the 
MAOP reconfirmation requirements, updating an applicability reference, 
and considering removing the term ``hydrostatic'' while allowing other 
authorized testing procedures. For the requirements related to electric 
resistance welded (ERW) pipe, the GPAC recommended PHMSA delete the 
phrase related to pipe body cracking and have those requirements be 
addressed in a new section within the IM regulations related to crack 
defects.
3. PHMSA Response
    PHMSA appreciates the information provided by the commenters 
regarding the consideration of seismicity and manufacturing- and 
construction-related defects under the IM regulations. After 
considering these comments as well as recommendations by the GPAC, 
PHMSA is revising Sec.  192.917(e)(2) to require operators monitor 
operating pressure cycles and periodically determine if the cyclic 
fatigue analysis is valid at least once every 7 calendar years, not to 
exceed 90 months, as necessary. PHMSA is also deleting a reference to 
the MAOP reconfirmation requirements in Sec.  192.624 and is 
referencing the new Sec.  192.712 for fracture mechanics analysis. 
PHMSA believes these changes are consistent with current IM 
requirements and will increase regulatory flexibility while maintaining 
pipeline safety.
    In Sec.  192.917(e)(3), PHMSA deleted a cross-reference to the MAOP 
reconfirmation requirements in Sec.  192.624 and replaced it with a 
requirement to prioritize the pipeline segment if it has experienced an 
in-service reportable incident since its most recent successful subpart 
J pressure test due to an original manufacturing-related defect; or a 
construction-, installation-, or fabrication-related defect. This 
clarifies that the IM requirement in Sec.  192.917(e)(3) is not part of 
the MAOP reconfirmation standards. Although the GPAC asked PHMSA to 
consider removing the term ``hydrostatic'' and allow other testing 
procedures, PHMSA is retaining the term ``hydrostatic'' in Sec.  
192.917(e)(3), as the proposed revision, as written, addresses NTSB 
recommendation P-11-15. The NTSB specifically recommended that PHMSA 
amend part 192 so that manufacturing- and construction-related defects 
can only be considered stable following a postconstruction hydrostatic 
pressure test of at least 1.25 times the MAOP. Therefore, deleting the 
word ``hydrostatic'' would be contrary to the letter and intent of this 
NTSB recommendation.
    For the requirements related to ERW pipe in Sec.  192.917(e)(4), 
PHMSA has deleted the phrase related to pipe body cracking and deleted 
a cross-reference to the MAOP reconfirmation requirements in Sec.  
192.624, referencing the new Sec.  192.712 for fracture mechanics 
analysis instead for cracking and crack-related issues. PHMSA made 
these changes to streamline the regulations and increase readability.

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

1. Summary of PHMSA's Proposal
    Section 5 of the 2011 Pipeline Safety Act identifies a technical 
correction amending 49 U.S.C. 60109(c)(3)(B) to allow the Secretary of 
Transportation to extend the 7-calendar-year IM reassessment interval 
for an additional 6 months if the operator submits written notice to 
the Secretary with sufficient justification of the need for the 
extension. The NPRM proposed to codify this technical correction as 
required by the statute.
2. Summary of Public Comment
    PHMSA received a comment regarding the 6-month grace period for the 
7-calendar-year reassessment interval from a trade organization 
expressing general support of the proposed provisions and requesting 
that PHMSA clarify that the 6-month extension begins after the close of 
the 7-calendar-year reassessment interval period, which would be 
consistent with

[[Page 52209]]

the 2011 Pipeline Safety Act revision to the Federal Pipeline Safety 
Statutes.
    At the GPAC meeting on January 12, 2017, the GPAC voted that the 
proposed changes on the 6-month grace period for the reassessment 
intervals are technically feasible, reasonable, cost-effective, and 
practicable, and did not recommend that PHMSA modify these proposed 
provisions.
3. PHMSA Response
    PHMSA appreciates the information provided by the commenters 
regarding the grace period for IM reassessment intervals. After 
considering the comment and as recommended by the GPAC, PHMSA is 
retaining the proposed revisions to Sec.  192.939 in this final rule. 
The proposed rule clearly stated that the 6-month extension begins 
after the close of the 7-calendar-year reassessment interval period. 
This is mirrored in PHMSA's frequently asked questions (FAQ) for the IM 
program,\72\ which clarifies that the maximum interval for reassessment 
may be set using the specified number of calendar years in accordance 
with the 2011 Pipeline Safety Act. The use of calendar years is 
specific to gas pipeline reassessment interval years under IM and does 
not alter the interval requirements that appear elsewhere in the code 
for various inspection and maintenance requirements.
---------------------------------------------------------------------------

    \72\ FAQ-41 at https://primis.phmsa.dot.gov/gasimp/faqs.htm.
---------------------------------------------------------------------------

E. ILI Launcher and Receiver Safety--Sec.  192.750

1. Summary of PHMSA's Proposal
    PHMSA determined that more explicit safety requirements are needed 
when performing maintenance activities that use launchers and receivers 
for inserting and removing ILI maintenance tools and devices. The 
current regulations for hazardous liquid pipelines under part 195 have, 
since 1981, contained safety requirements for scraper and sphere 
facilities. However, the current regulations for natural gas 
transmission pipelines do not similarly require controls or 
instrumentation to protect against an inadvertent breach of system 
integrity due to the incorrect operation of launchers and receivers for 
ILI tools, or scraper and sphere facilities. As a result, PHMSA 
proposed to add a new section to the Federal Pipeline Safety 
Regulations to require ILI launchers and receivers include a suitable 
means to relieve pressure in the barrel and either a means to indicate 
the pressure in the barrel or a means to prevent opening if pressure 
has not been relieved. While most launchers and receivers are already 
equipped with such devices, some older facilities may not be so 
equipped. Under the proposed provisions, operators would be required to 
have this safety equipment installed consistent with current industry 
practice.
2. Summary of Public Comment
    Stakeholders, including TPA, provided input on PHMSA's changes to 
the requirements for safety when performing maintenance activities that 
utilize launchers and receivers for inserting and removing inspection 
and maintenance tools and devices. TPA supported the proposed safety 
additions to the regulations but stated that Sec.  192.750 should be 
included within the regulations for pipeline components rather than the 
subpart for pipeline maintenance. In addition, TPA suggested PHMSA 
revise the language to allow 18 months after the effective date of the 
rule to comply with the provisions. This change would allow for more 
time to plan, budget, and complete the work safely. Another commenter 
recommended these provisions be effective prior to the next time an 
operator would use an applicable launcher or receiver. Public interest 
groups and others, such as PST and NAPSR, had broad support for the 
proposed provisions regarding ILI launcher and receiver safety.
    At the GPAC meeting on January 12, 2017, a public commenter 
suggested clarification on PHMSA's use of the term ``relief device'' or 
``relief valve'' within the proposed provisions. During discussion, the 
committee noted that there are requirements for ``relief valves'' 
elsewhere in the code, and calling a needed safety device for ILI 
launchers and receivers a ``relief valve'' would then make it subject 
to those additional requirements. Based on that discussion, the 
committee recommended that PHMSA modify the proposed rule to clarify 
that the rule does not require ``relief valves'' or use ``relief 
valve'' as an officially defined term within the provision, as those 
terms have distinct meanings within the broader context of the Federal 
Pipeline Safety Regulations.
3. PHMSA Response
    PHMSA appreciates the information provided by the commenters 
regarding launcher and receiver safety. After considering these 
comments and the GPAC input, PHMSA is finalizing the provisions as they 
were proposed in the NPRM, with the exception of a compliance date 1 
year after the effective date of the rule. This approach avoids 
disruption of work planned within a year of the effective date of the 
rule, and it allows operators that are not planning work until beyond 
the 1-year grace period to implement the upgrade before the next 
planned use. Therefore, special modification work would not be required 
before the launcher or receiver is needed. Operators would not be 
required to perform the upgrades until the launcher or receiver is to 
be used.
    Consistent with the originally proposed language, this final rule 
does not use the term ``relief valve'' and instead uses the generic 
phrase ``device capable of safely relieving pressure.'' The proposed 
rule effectively avoided any potential for confusion with respect to 
the defined term ``relief valve'' and the requirements associated with 
those components, therefore no change to this wording was necessary for 
this final rule.
    PHMSA believes that this requirement is appropriately located in 
subpart M, ``Maintenance,'' of part 192, and notes that the comparable 
requirement in part 195 for hazardous liquid pipelines is located in 
subpart F, ``Operations and Maintenance.''

F. MAOP Exceedance Reporting--Sec. Sec.  191.23, 191.25

1. Summary of PHMSA's Proposal
    Section 23 of the 2011 Pipeline Safety Act requires that operators 
report each exceedance of a pipeline's MAOP beyond the build-up allowed 
for the operation of pressure-limiting or control devices. On December 
21, 2012 (77 FR 75699), PHMSA published Advisory Bulletin ADB-2012-11 
to advise operators of their responsibility under section 23 of the 
2011 Pipeline Safety Act to report such exceedances. The advisory 
bulletin further stated that the reporting requirement is applicable to 
all gas transmission pipeline facility owners and operators. PHMSA 
advised pipeline owners and operators to submit this information in the 
same manner as safety-related condition reports. The information 
pipeline owners and operators submit should comport with the 
information listed at Sec.  191.25(b), and pipeline owners and 
operators submitting such information should use the reporting methods 
listed at Sec.  191.25(a).
    Although this provision of the 2011 Pipeline Safety Act is self-
executing, PHMSA proposed to revise the safety-related condition 
reporting requirements under part 191 to codify this requirement and 
harmonize part 191 with the statutory requirement by eliminating the 
reporting exemption and to provide a consistent procedure,

[[Page 52210]]

format, and structure for operators to submit such reports.
2. Summary of Public Comment
    Trade associations, citizen groups, and pipeline industries 
generally supported PHMSA's codification of the statutory reporting 
requirements for MAOP exceedances for transmission lines.
    API and GPA objected to MAOP exceedance reporting requirements for 
unregulated gathering pipelines. GPA stated that PHMSA did not 
sufficiently weigh the benefits of reporting MAOP exceedance against 
the hurdles to compliance for unregulated gathering pipelines. GPA also 
questioned whether PHMSA has the authority to require unregulated 
gathering pipelines report MAOP exceedance, since complying with this 
reporting requirement would necessitate that unregulated gathering 
pipelines establish MAOP, which they are currently not required to do. 
Citizen and other safety groups, including Earthworks, NAPSR, the 
Pipeline Safety Coalition, and PST, supported the inclusion of 
unregulated gathering pipelines in this section, stating that it would 
improve pipeline safety.
    Several commenters suggested editorial revisions to streamline and 
improve these provisions. NGA expressed concern that the proposed 
provisions could apply to distribution systems and suggested that PHMSA 
clarify that reporting requirements for MAOP exceedance only apply to 
transmission pipelines. Additionally, Spectra Energy Partners requested 
that PHMSA require reporting of MAOP exceedances only when the operator 
is unable to respond to MAOP exceedances within the timeframe required 
elsewhere in part 192.
    One operator expressed concern that the proposed change would 
require operators to submit additional safety-related condition reports 
anytime the operator had to implement a pressure reduction upon 
discovering an immediate condition.
    At the GPAC meeting on June 7, 2017, there was brief discussion on 
whether the 5-day reporting requirement was too prescriptive, but the 
committee agreed that PHMSA was properly implementing the statutory 
requirement as written and intended by Congress. Following that 
discussion, the committee recommended that PHMSA modify the proposed 
rule to clarify that the MAOP exceedance reporting provisions do not 
apply to gathering lines.
3. PHMSA Response
    PHMSA appreciates the information provided by the commenters 
regarding MAOP exceedance reporting. The 2011 Pipeline Safety Act 
mandates that an operator report MAOP exceedances on gas transmission 
lines, regardless of whether the operator corrects the safety-related 
condition through repair or replacement. After considering the comments 
PHMSA received on the NPRM and as recommended by the GPAC, PHMSA is 
inserting the word ``only'' in the additional MAOP exceedance reporting 
provision in Sec.  191.23(a)(10) to make it clearer that the amended 
requirement applies only to gas transmission lines and not to gathering 
or distribution lines. Conforming changes were made to Sec.  
191.23(a)(6). PHMSA notes that the prior safety-related condition 
reporting requirements and exceptions related to pressure exceedances 
for gathering and distribution lines have not been altered.

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

1. Summary of PHMSA's Proposal
    In the NPRM, PHMSA proposed to revise Sec.  192.150 to incorporate 
by reference a NACE Standard Practice, NACE SP0102-2010, ``In-line 
Inspection of Pipelines,'' to promote a higher level of safety by 
establishing consistent standards for the design and construction of 
pipelines to accommodate ILI devices.
    In Sec.  192.493, PHMSA proposed requirements for operators to 
comply with the requirements and recommendations of API STD 1163, In-
line Inspection Systems Qualification Standard; ANSI/ASNT ILI-PQ-2005, 
In-line Inspection Personnel Qualification and Certification; and NACE 
SP0102-2010, In-line Inspection of Pipelines. PHMSA also proposed to 
allow operators to conduct assessments using tethered or remotely 
controlled tools.
2. Summary of Public Comment
    NAPSR supported the proposed provisions in Sec.  192.493, 
commenting that the incorporation by reference of the three consensus 
standards provides enhanced guidance for the determination of adequate 
procedures and qualifications related to in-line inspections of 
transmission pipelines.
    Some industry representatives commented that it is unnecessary to 
incorporate American Society for Nondestructive Testing (ASNT) ILI-PQ 
by reference since API 1163 requires that providers of ILI services 
ensure that their employees are qualified. Others commented that PHMSA 
should exclude requirements contained in section 11 of API 1163, which 
pertains to quality management systems. Lastly, industry 
representatives asserted that ILI vendors may not be able to meet the 
90 percent tool tolerance specified in the referenced standards, and 
PHMSA should relocate these proposed requirements to a different 
subpart.
    Several commenters noted that if PHMSA required compliance with 
``the requirements and recommendations of'' the recommended practices 
and standards, it would create enforceable requirements out of actions 
that the standards themselves did not necessarily mandate.
    During the GPAC meeting of March 2, 2018, the committee recommended 
PHMSA revise this provision by striking the phrase ``the requirements 
and the recommendations of,'' so that recommendations within the 
incorporated standard would not be made mandatory requirements.
3. PHMSA Response
    PHMSA appreciates the information provided by the commenters 
regarding the incorporation by reference of industry standards for ILI. 
After considering these comments and as recommended by the GPAC, PHMSA 
is deleting the phrase ``the requirements and the recommendations of'' 
from Sec. Sec.  192.150 and 192.493 so that the recommendations within 
the incorporated standard would not be made mandatory requirements.
    PHMSA believes that the inclusion of the NACE standard at Sec.  
192.150 will help to address the NTSB recommendation P-15-20, which 
asked PHMSA to identify all operational complications that limit the 
use of ILI tools in piggable pipelines, develop methods to eliminate 
those complications, and require operators use such methods to increase 
the use of ILI tools. PHMSA also believes that more pipelines will 
become piggable in the future as the nation's pipeline infrastructure 
ages and is eventually replaced. A current provision in the regulations 
requires that all new and replaced pipeline be piggable, and as 
operators address higher-risk infrastructure through this rulemaking, 
there is a likelihood that some previously unpiggable pipe will be 
replaced.
    PHMSA disagrees that ASNT ILI-PQ is unnecessary. The foreword of 
API 1163 states ``This standard serves as an umbrella document to be 
used with and complement companion standards.

[[Page 52211]]

NACE SP0102, In-line Inspection of Pipelines and ASNT ILI-PQ, In-line 
Inspection Personnel Qualification and Certification.'' These three 
standards are complimentary and are intended to be used together. PHMSA 
also disagrees that quality requirements should be excluded from the 
rule. One of the fundamental objectives of this rule is to establish a 
minimum standard for quality in conducting ILI. Also, the consensus 
industry standard API 1163 only uses 90 percent tool tolerance as an 
example to illustrate key points but does not specify or establish a 
minimum standard tool tolerance of 90 percent.

G. Strengthening Assessment Requirements--Sec. Sec.  192.150, 192.493, 
192.921, 192.937, Appendix F

ii. Expand Assessment Methods Allowed for IM--Sec. Sec.  192.921(a) and 
192.937(c)

1. Summary of PHMSA's Proposal
    In the current Federal Pipeline Safety Regulations, Sec.  192.921 
requires that operators with pipelines subject to the IM rules must 
perform integrity assessments. Currently, operators can assess their 
pipelines using ILI, pressure test, direct assessment, and other 
technology that the operator demonstrates provides an equivalent level 
of understanding of the condition of the pipeline.
    In the NPRM, PHMSA proposed to require that direct assessment only 
be allowed when the pipeline cannot be assessed using ILI. As a 
practical matter, direct assessment is typically not chosen as the 
assessment method if the pipeline can be assessed using ILI. Further, 
PHMSA proposed to add three additional assessment methods to the 
regulations:
    1. A spike hydrostatic pressure test, which is particularly well-
suited to address stress corrosion cracking and other cracking or 
crack-like defects;
    2. Guided Wave Ultrasonic Testing (GWUT), which is particularly 
appropriate in cases where short segments such as road or railroad 
crossings are difficult to assess; and
    3. Excavation with direct in situ examination.
2. Summary of Public Comment
    NAPSR expressed its support for the proposed provisions. Many 
comments expressed concerns with the proposed provisions for the 
assessment methods regarding uncertainties in reported results. 
Multiple commenters stated that operators should be able to run the 
appropriate assessment or ILI tools for the threats that are known or 
likely to exist on the pipeline based on its condition. Atmos Energy 
commented that ASME/ANSI B318.S requirements should be the standard to 
which operators are required to follow. Enable Midstream Partners 
proposed that PHMSA add ``significant'' to make a distinction between 
significant and insignificant threats and offered specific language to 
address its concerns. PG&E commented on the proposed provisions for ILI 
assessments, requesting that PHMSA provide guidance as to how to 
explicitly consider the numerous uncertainties associated with ILI 
regarding anomaly location accuracy, detection thresholds, and sizing 
accuracy, and suggested that PHMSA allow industry guidance and best 
practices to be used where practical. Some commenters expressed concern 
that PHMSA proposed to add requirements surrounding the detection of 
anomalies that many ILI tools could not meet. These commenters stated 
that there are no tools designed to find girth weld cracks and that 
most incidents caused by girth weld cracks have third-party excavation 
damage as a contributing factor. Commenters further stated that this is 
a threat that is best handled by procedures that require caution around 
girth welds during excavation and backfilling procedures.
    Several entities commented on the proposed qualification 
requirements under the ILI assessment method provisions, expressing 
concern that they are redundant with existing operator qualification 
regulations under the IM regulations at Sec.  192.915 and the proposed 
revisions to Sec.  192.493 incorporating the industry ANSI standard on 
ILI personnel qualification. Multiple entities proposed changes to 
remove such redundancies and improve clarity.
    Commenters requested clarification that the proposed text in the IM 
assessment provisions ``apply one or more of the following methods for 
each threat to which the covered segment is susceptible'' does not mean 
that at least one assessment is required for each threat. Additionally, 
commenters disagreed with adding an explicit requirement for a ``no 
objection'' letter as notification of using ``other technology'' and 
suggested that if this notification is required, operators should be 
allowed to proceed with the technology if they do not receive a ``no 
objection'' letter from PHMSA within a certain period.
    The NTSB commented that PHMSA's proposal to revise the pipeline 
inspection requirements to allow the direct assessment method to be 
used only if a line is not capable of inspection by internal inspection 
tools directly conflicts with the recommendations of their pipeline 
safety study, Integrity Management of Gas Transmission Lines in High 
Consequence Areas, which recommended that PHMSA develop and implement a 
plan for eliminating the use of direct assessment as the sole integrity 
assessment method for gas transmission pipelines. The CPUC asserted 
that direct assessment must always be supplemented with other methods, 
such as ILI or a pressure test.
    Many industry entities argued that PHMSA's proposed changes to the 
IM assessment provisions limiting direct assessment to unpiggable lines 
are not technically justified. Several entities, including AGA and API, 
believed it was unreasonable to limit operators' ability to use direct 
assessment for pipeline assessments unless all other assessment methods 
have been determined unfeasible or impractical. PG&E requested that 
PHMSA recognize that although a pipeline may be considered piggable, it 
does not mean that ILI technology is available, and they provided 
specific suggestions for revision. Similarly, AGA stated that free-
swimming flow-driven ILI tools are often not compatible with intrastate 
transmission lines for several reasons, stating that certain conditions 
must exist to assess a pipeline by ILI and obtain valid data, including 
adequate flow rate, lack of bends or valves that would impede diameter, 
and ability to insert and remove the tool from the system. Therefore, 
AGA provided a suggested definition for ``able to accommodate 
inspection by means of an instrumented in-line inspection tool.''
    Trade associations asserted that direct assessment is a proven 
assessment technique that works in addressing the threat of corrosion. 
INGAA stated that the criteria for when direct assessment can be used 
should depend on whether direct assessment can provide the necessary 
information about the pipe condition rather than whether other 
assessment methods can be used. AGA commented that it is not aware of 
any industry study that would suggest that direct assessment does not 
work effectively to identify corrosion defects in certain 
circumstances, which it describes in its comments. In addition, AGA 
stated that direct assessment is a predictive tool that identifies 
areas where corrosion could occur, including time-dependent threats, 
while other methods can only detect where corrosion has resulted in a 
measurable metal loss. Atmos Energy commented that limiting the use of 
direct assessment only to those pipeline segments that are not capable 
of

[[Page 52212]]

inspection by internal inspection tools is not consistent with other 
requirements of subpart O.
    At the GPAC meeting on December 15, 2017, the committee voted to 
revise the ``no objection'' process to incorporate language stating 
that, if an operator does not receive an objection letter from PHMSA 
within 90 days of notifying PHMSA of an alternative sampling approach, 
the operator can proceed with their method. Additionally, the GPAC, 
during the meeting on March 2, 2018, recommended that PHMSA change 
these provisions to clarify that operators should select the 
appropriate assessment based on the threats to which the pipeline is 
susceptible and remove certain language that is duplicative to another 
existing section of the regulations. The GPAC also recommended that 
PHMSA clarify that direct assessment is allowed where appropriate but 
may not be used to assess threats for which the method is not suitable. 
Further, the GPAC wanted PHMSA to incorporate the notification and 
objection procedure and 90-day timeframe that the GPAC approved under 
the material properties verification requirements.
3. PHMSA Response
    PHMSA appreciates the information provided by the commenters 
regarding the inclusion of additional assessment methods for integrity 
assessments. After considering these comments and as recommended by the 
GPAC, PHMSA is clarifying in this final rule that operators should 
select the appropriate assessment method based on the threats to which 
the pipeline is susceptible and is removing language regarding the 
qualification of persons reviewing ILI results that is duplicative with 
existing Sec.  192.915. PHMSA is also clarifying in Sec.  192.921 that 
direct assessment is allowed where appropriate but may not be used to 
assess threats for which the method is not suitable, such as assessing 
pipe seam threats. In addition, PHMSA incorporated the notification 
procedure under Sec.  192.18 with the 90-day timeframe and objection 
process.
    PHMSA notes that other comments regarding the determination of 
suitable assessment methods for applicable threats and ILI tool 
capabilities relate to long-standing IM regulations that were not 
proposed for revision. PHMSA did provide substantial additional 
guidance and standards for implementing the integrity assessment 
requirements for ILI by incorporating the industry standards in Sec.  
192.493, as discussed in the previous sections.

G. Strengthening Assessment Requirements--Sec. Sec.  192.150, 192.493, 
192.921, 192.937, Appendix F

iii. Guided Wave Ultrasonic Testing--Appendix F

1. Summary of PHMSA's Proposal
    When expanding assessment methods for both HCA and non-HCA areas, 
PHMSA proposed to add three additional assessment methods, one being 
GWUT. Under the existing regulations, GWUT is considered ``other 
technology,'' and operators must notify PHMSA prior to its use. PHMSA 
developed guidelines for the use of GWUT, which have proven successful, 
and proposed to add them under a new Appendix F to part 192--Criteria 
for Conducting Integrity Assessments Using Guided Wave Ultrasonic 
Testing. As such, future notifications to PHMSA would not be required, 
representing a cost savings for operators.
2. Summary of Public Comment
    Multiple entities commented in support of using GWUT and the 
inclusion of proposed Appendix F. NAPSR expressed its agreement with 
and support for the proposed Appendix. American Public Gas Association 
(APGA) applauded PHMSA for including guidelines for GWUT; however, it 
cautioned that the guidance only specifies Guided Ultrasonics LTD (GUL) 
Wavemaker G3 and G4, which use piezoelectric transducer technology, as 
acceptable technology. APGA recommended that Magnetostrictive Sensor 
technology also be included as an acceptable guided wave technology, 
stating that at least one of its members reported good results using 
this technology for guided wave assessment of an unpiggable segment of 
a transmission pipeline.
    A commenter noted that the requirement of both torsional and 
longitudinal wave modes in all situations introduces unnecessary 
complexity into the GWUT data interpretation process. The commenter 
further noted that PHMSA should specify that torsional wave mode is the 
primary wave mode when utilizing GWUT, and that longitudinal wave mode 
may be used as an optional, secondary mode. Other commenters 
recommended additional changes to Appendix F, such as stating that 
qualified GWUT equipment operators are trained to understand the 
strengths, weaknesses, and proper applications of each wave mode and 
should have the freedom to select the appropriate and most effective 
wave mode(s) for the given situation. PG&E requested that PHMSA 
recognize that this technology is used at locations other than casings 
as implied in the introductory paragraph and commented that double-
ended inspections are not always required to meet the specification.
    During the GPAC meeting on December 15, 2017, the GPAC agreed with 
the provisions related to Appendix F and GWUT but recommended PHMSA 
revise the ``no objection'' letter process.
3. PHMSA Response
    PHMSA appreciates the information provided by the commenters 
regarding GWUT. After considering these comments and as recommended by 
the GPAC, PHMSA is removing the reference to GUL equipment for clarity. 
PHMSA is modifying the notification process to allow operators to 
proceed with an alternative process for using GWUT if the operator does 
not receive an objection letter from PHMSA within 90 days of notifying 
PHMSA in accordance with Sec.  192.18. PHMSA believes this change 
increases regulatory flexibility while maintaining pipeline safety.
    In this final rule, PHMSA is retaining the requirement to use both 
torsional and longitudinal wave modes since that is a long-standing 
requirement in PHMSA's guidance for accepting GWUT as an allowed 
technology under an ``other technology'' notification. Also, PHMSA 
recognizes that GWUT is used at locations other than casings, although 
it is most often deployed for the integrity assessment of cased 
crossings. However, double-ended inspections would not always be 
required to meet Appendix F, and Appendix F does not require double-
ended inspections. Double-ended inspections are not necessary as long 
as the guided wave ultrasonic test covers the entire length of the 
assessment as well as the ``dead zone'' where the equipment is set up.
    The proposed rule already addresses validation of operator 
training, but in this final rule, PHMSA is deleting the sentence 
``[t]here is no industry standard for qualifying GWUT service 
providers'' to provide clarity.

H. Assessing Areas Outside of HCAs--Sec. Sec.  192.3, 192.710

i. MCA Definition--Sec.  192.3

1. Summary of PHMSA's Proposal
    In the NPRM, PHMSA introduced a new definition for a Moderate 
Consequence Area (MCA). The proposed rule defined an MCA as an onshore 
area, not meeting the definition of an HCA, that is within a potential 
impact circle, as defined in Sec.  192.903, containing 5 or more 
buildings intended

[[Page 52213]]

for human occupancy; an occupied site; or a right-of-way for a 
designated interstate, freeway, expressway, or other principal four-
lane arterial roadway as defined in the Federal Highway 
Administration's ``Highway Functional Classification Concepts, Criteria 
and Procedures.'' PHMSA proposed that requirements for data analysis, 
assessment methods, and immediate repair conditions within these MCAs 
would be similar to requirements for HCA pipeline segments but with 
longer timeframes so that operators could properly allocate resources 
to higher-consequence areas. PHMSA proposed that the 1-year repair 
conditions that currently exist for HCA pipeline segments would be 2-
year repair conditions when found on MCA pipeline segments. These 
changes would ensure the prompt remediation of anomalous conditions 
that could potentially affect people, property, or the environment, 
commensurate with the severity of the defects, while still allowing 
operators to allocate their resources to HCAs on a higher-priority 
basis.
2. Summary of Public Comment
    The NTSB stated that the proposed provisions to create an MCA 
category and include a highway size threshold in the definition of an 
MCA accomplishes part of what the NTSB intended in Safety 
Recommendation P-14-1. However, the NTSB objected to the proposed 
highway coverage as being limited to four lanes and stated its support 
of expanding the highway size threshold as they had specifically 
recommended in P-14-1. The NTSB asserted that the proposed language 
would exclude the category of other principal arterial roadways wider 
than four lanes when, in fact, the wider roadways should be included.
    INGAA supported the addition of an MCA category to the Federal 
Pipeline Safety Regulations but recommended several modifications to 
the proposed definition. INGAA suggested PHMSA should limit the 
definition of an MCA to only those pipeline segments that could be 
assessed through an ILI inspection, amend the MCA definition to avoid 
ambiguity regarding residential structures, remove ``outside areas and 
open structures'' from the portion of the definition of MCA related to 
``identified sites,'' include timeframes for incorporating changes to 
existing MCAs, and permit operators to use the edge of the pavement 
rather than the highway right-of-way to determine if a roadway 
intersects with a Potential Impact Circle.
    AGA, API, APGA, and several pipeline entities agreed with INGAA's 
comments on the modification to PHMSA's proposed MCA definition. 
Additionally, AGA, API, and APGA emphasized PHMSA should remove the 
reference to ``a right-of-way'' for the designated roadways, commenting 
that the MCA definition could be interpreted so that if a Potential 
Impact Circle touches any portion of the roadway right-of-way, the 
pipeline segment is an MCA. That interpretation would put undue burden 
on operators in areas where its pipelines lay at or near the edge of 
the public right-of-way that would not normally contain ``persons or 
property'' that would sustain damage or loss in the event of a pipeline 
failure. Further, API added that the reference to ``a right-of-way'' is 
problematic because roadway right-of-ways are variable, cannot be seen 
with the naked eye, and are often not included in publicly available 
data sources.
    Commenters also disagreed with the definition of ``occupied site'' 
within the MCA definition. GPA asserted that the criterion used in the 
MCA definition should be limited to interstate highways, and the 
definition of ``occupied site'' should be eliminated to more clearly 
distinguish between MCAs and HCAs and to provide greater clarity in 
identifying and managing MCAs. Similarly, Enlink Midstream commented 
that PHMSA should eliminate the definition of occupied site and remove 
this criterion from the proposed definition of MCA. Doing so would 
permit the continued focus on HCAs that the IM process was intended to 
accomplish. AGL Resources also expressed concern with the proposed 
definition of occupied site, commenting that this definition could 
require operators to effectively perform a census-like identification 
of structures to verify the count of persons within that structure.
    There were conflicting viewpoints on where the definition of MCA 
should be placed in the regulations. API and other commenters stated 
that they preferred a new category and a distinct definition for MCA as 
opposed to expanding the definition of HCA or making a subcategory in 
the HCA definition for MCAs, whereas SoCalGas encouraged expanding the 
scope of HCAs rather than creating a new category.
    Enterprise Products commented PHMSA should move the MCA definition 
to subpart O and remove the ``occupied site'' criteria from the 
proposed definition of MCA, which would provide more distinction 
between MCAs and HCAs in the regulations and would also more 
appropriately place them under the IM regulations.
    AGA and several other organizations expressed concern over the 
resource-intensive administrative task of identifying MCAs, especially 
pertaining to recordkeeping requirements. API asserted that the 
proposed provisions would limit operators' ability to prioritize 
resources for pipelines that pose the highest risk. They further stated 
that while they agree with the inclusion of all Class 3 and Class 4 
locations, occupied sites, and major roadways in the definition of MCA, 
they disagree with the proposed threshold of five buildings intended 
for human occupancy within the potential impact radius. They suggested 
that a more appropriate threshold would be more than 10 buildings 
intended for human occupancy, as that number is consistent with 
longstanding part 192 class location designations.
    Multiple groups, such as AGI, INGAA, and Cheniere Energy, also 
stated objections over various aspects of defining and identifying MCAs 
and provided suggestions for revised language, including several broad 
clarifications or deletions to the definition. In addition to 
requesting modifications to the definition of MCA, INGAA objected to 
the provided geographic information system (GIS) layer for right-of-way 
determination, and suggested that PHMSA provide one database for 
roadway classification. Numerous trade associations and pipeline 
companies asked PHMSA to consider a qualifier that the definition of 
MCA only applies to pipelines operating at greater than 30 percent 
SMYS. EnLink Midstream suggested using a threshold level of 16-inch 
pipe diameter to identify pipelines that pose a greater risk.
    The GPAC had a comprehensive discussion on the MCA definition 
during the meeting on March 2, 2018, and approved of the definition 
with some changes. First, the GPAC recommended changing the highway 
description within the definition to remove reference to the roadway 
``rights-of-way'' and to add language so that the highway consists of 
``any portion of the paved surface, including shoulders.'' Secondly, 
the GPAC recommended clarifying that highways with 4 or more lanes are 
included, and they also wanted PHMSA to work together with the Federal 
Highway Administration to provide operators with clear information 
relative to this aspect of the rulemaking and discuss it in the 
preamble. The GPAC also recommended that PHMSA discuss in the preamble 
what they expect the definition of ``piggable'' to be, as it is 
critical for aspects of the MCA

[[Page 52214]]

definition as it relates to MAOP confirmation. Finally, the GPAC 
recommended PHMSA modify the term ``occupied sites'' in the MCA 
definition and in the definitions section of part 192 by removing the 
language referring to ``5 or more persons'' and the timeframe of 50 
days and tying the requirement into the HCA survey for ``identified 
sites'' as discussed by GPAC members and PHMSA at the meeting. The 
committee noted that such site identification could be made through 
publicly available databases and class location surveys. The committee 
suggested PHMSA consider the necessary sites and enforceability of the 
definition per direction by the committee members.
3. PHMSA Response
    PHMSA appreciates the information provided by the commenters 
regarding the definition of moderate consequence area. After 
considering these comments and the GPAC input, PHMSA is modifying the 
highway description within the definition to remove reference to the 
roadway ``rights-of-way'' and to add language so that the highway 
consists of ``any portion of the paved surface, including shoulders.'' 
Also, PHMSA is specifying that highways with 4 or more lanes are 
included. PHMSA believes these changes provide additional clarity.
    Per the GPAC's request that PHMSA provide additional guidance on 
what roadways are included in the MCA definition as it pertains to 
``other principal roadways with 4 or more lanes,'' PHMSA notes that the 
Federal Highway Administration defines Other Principal Arterial 
roadways \73\ as those roadways that serve major centers of 
metropolitan areas, provide a high degree of mobility, and can also 
provide mobility through rural areas. Unlike their access-controlled 
counterparts (interstates, freeways, and expressways), abutting land 
uses can be served directly. Forms of access for Other Principal 
Arterial roadways include driveways to specific parcels and at-grade 
intersections with other roadways. For the most part, roadways that 
fall into the top three functional classification categories 
(Interstate, Other Freeways & Expressways, and Other Principal 
Arterials) provide similar service in both urban and rural areas. The 
primary difference is that there are usually multiple arterial routes 
serving a particular urban area, radiating out from the urban center to 
serve the surrounding region. In contrast, an expanse of a rural area 
of equal size would be served by a single arterial. The MCA definition 
does not include all roadways that meet this definition but instead is 
limited to those roadways meeting this definition that have four or 
more lanes.
---------------------------------------------------------------------------

    \73\ Federal Highway Administration, Office of Planning, 
Environment, & Realty (HEP), Highway Functional Classification 
Concepts, Criteria and Procedures (2013) https://www.fhwa.dot.gov/planning/processes/statewide/related/highway_functional_classifications/section03.cfm#Toc336872980.
---------------------------------------------------------------------------

    With respect to ``occupied sites,'' PHMSA evaluated the comments 
and the GPAC discussion and concluded that including occupied sites 
within the MCA definition was not necessary. Industry representatives 
on the GPAC asserted that most locations meeting the definition of 
occupied site are, as a practical matter, already included as an 
identified site and designated as an HCA. Commenters suggested most 
operators find it expedient to declare sites similar to occupied areas 
as HCAs instead of counting the specific occupancy of such locations to 
see if they meet the occupancy standard over the course of a year. 
Operators then monitor occupancy in subsequent years for changes that 
might change the site's status as an occupied site. Such an approach 
would require fewer resources and be more conservative from a public 
safety standpoint. Based on these comments, PHMSA is persuaded that 
including another category of locations, similar to identified sites in 
HCAs but with a lower occupancy standard of 5 persons, is unnecessarily 
burdensome without a comparable decrease in risk.
    PHMSA disagrees that the MCA definition should be moved to subpart 
O. The term is used in sections outside of subpart O. Including the MCA 
definition in Sec.  192.3 is necessary for it to apply to the sections 
in which it is used throughout part 192.

H. Assessing Areas Outside of HCAs--Sec. Sec.  192.3, 192.710

ii. Non-HCA Assessments--Sec.  192.710

1. Summary of PHMSA's Proposal
    PHMSA proposed to add a new Sec.  192.710 to require that pipeline 
segments in Class 3 or Class 4 locations, and piggable segments in 
MCAs, be initially assessed within 15 years and no later than every 20 
years thereafter on a recurring basis. PHMSA also proposed to require 
assessments in these areas be conducted using the same methods that are 
currently allowed for HCAs. PHMSA has found that operators have 
assessed significant non-HCA pipeline mileage in conjunction with 
performing HCA integrity assessments in the same pipeline. Therefore, 
PHMSA proposed to allow the use of those prior assessments of non-HCA 
pipeline segments to comply with the new Sec.  192.710.
    In effect, to this limited population of pipeline segments outside 
of HCAs, PHMSA proposed to expand the applicability of IM program 
elements related to baseline integrity assessments, remediating 
conditions found during integrity assessments, and periodic 
reassessments. In addition, under the proposed provisions, MCAs would 
be subject to other requirements related to the congressional mandates, 
including material properties verification and MAOP reconfirmation. Any 
assessments an operator would conduct to reconfirm MAOP under proposed 
Sec.  192.624 would count as an initial assessment or re-assessment, as 
applicable, under the proposed requirements for non-HCA assessments.
2. Summary of Public Comment
    The NTSB and multiple citizen groups supported the expansion of IM 
elements to gas transmission pipelines in areas outside those currently 
defined as HCAs. However, several entities, including PST, stated that 
applying a limited suite of IM tools to these areas was insufficient 
and requested that the full suite of IM elements be applied to the 
additional pipeline segments. Some citizen groups expressed concern 
that the 15-year implementation period and 20-year re-inspection period 
was too long.
    While pipeline companies and trade associations generally supported 
PHMSA's efforts to expand IM elements beyond HCAs, many of them stated 
concerns over the time and cost required to identify MCAs, the efficacy 
of the changes, and the language and requirements regarding both the 
limitation of assessments to pipeline segments accommodating inline 
inspection tools and (re)assessment periods. Many groups requested a 
clear, concise set of codified requirements for IM outside of HCAs to 
simplify identification, recordkeeping, and repairs.
    Several commenters provided input on the allowable assessment 
methods for non-HCAs. AGA suggested that PHMSA create a new subpart 
consisting of a clear and concise set of codified requirements for the 
non-HCA assessments, including new definitions regarding the limitation 
of assessments to pipeline segments accommodating instrumented inline 
inspection tools. Many trade associations and pipeline companies stated 
that they thought the direct assessment method could achieve a 
satisfactory level of inspection in place of costlier in-line 
inspection,

[[Page 52215]]

especially given the additional detail added to the in-line inspection 
assessment method in the proposal. API requested that PHMSA allow 
operators to rely on any prior assessments performed under subpart O 
requirements of part 192 in effect at the time of the assessment rather 
than limit the allowance to ILI. Furthermore, other organizations 
supported AGA's proposal that mirrors and extends to MCAs the two-
methodology approach used to determine HCAs in the existing Sec.  
192.903, which allows for identification based on class location or by 
the pipeline's potential impact radius.
    Entities, including API and Atmos Energy, requested clarification 
regarding assessment periods and reassessment intervals due to the 
language regarding shorter reassessment intervals ``based on the type 
[of] anomaly, operational, material and environmental conditions [. . 
.], or as otherwise necessary.'' Those commenters said that language 
was vague and subject to varying interpretations, so they suggested 
revisions to the language for the reassessment intervals. Lastly, AGA 
suggested that PHMSA define the term ``pipelines that can accommodate 
inspection by means of an instrumented in-line inspection tool'' used 
in proposed Sec. Sec.  192.710 and 192.624, stating that providing the 
criteria that a pipeline must meet to be able to accommodate an in-line 
inspection tool would remove uncertainty and inconsistency in 
determining which pipelines meet PHMSA's proposed qualifier.
    The GPAC discussed the provisions related to assessments outside of 
HCAs during the meeting on March 2, 2018. The GPAC found the provisions 
to be technically feasible, reasonable, cost-effective, and practicable 
if PHMSA clarified that direct assessment could be used only if 
appropriate for the threat being assessed and could not be used to 
assess threats for which direct assessment is not suitable, and removed 
the provisions related to low-stress assessments. The GPAC also 
recommended revising the initial assessment and reassessment intervals 
for applicable pipeline segments from an initial assessment within 15 
years of the effective date of the rule and periodic assessments every 
20 years thereafter to an initial assessment within 14 years of the 
effective date of the rule and periodic assessments every 10 years 
thereafter. The GPAC stated that the prioritization of initial 
assessments and reassessments should be based on the risk profiles of 
the pipelines. The GPAC also wanted PHMSA to apply the assessment and 
reassessment requirements only to pipelines with MAOPs greater than or 
equal to 30 percent SMYS.
3. PHMSA Response
    PHMSA appreciates the information provided by the commenters 
regarding integrity assessments outside HCAs. After considering these 
comments and as recommended by the GPAC, PHMSA is modifying the rule to 
specify that direct assessment may be used only if appropriate for the 
threat being assessed and cannot be used to assess threats for which 
direct assessment is not suitable, such as assessing pipe seam threats. 
PHMSA made these changes to provide clarity regarding the proper use of 
direct assessments.
    In addition, PHMSA is revising the applicability of Sec.  192.710 
to apply only to pipelines with an MAOP of greater than or equal to 30 
percent of SMYS. PHMSA made this change because the GPAC recommended it 
was cost-effective for the provision to only apply to pipe operating 
above 30% SMYS in Class 3 and 4 locations and because those pipelines 
present the greatest risk to safety. Because of this modification, 
PHMSA is withdrawing provisions related to low-stress assessments since 
they will no longer be applicable.
    Based on the comments and recommendations from the GPAC, PHMSA is 
also modifying the initial assessment deadline and reassessment 
intervals for applicable pipeline segments to 14 years after the 
publication date of the rule and every 10 years thereafter, which was 
reduced from 15 years and 20 years, respectively. PHMSA believes this 
change increases regulatory flexibility while maintaining pipeline 
safety. PHMSA is also adding a requirement that the initial assessments 
must be scheduled using a risk-based prioritization.
    PHMSA disagrees with the need to implement a dual approach to MCA 
identification that would be similar to the ways that HCAs are 
identified. Subpart O and the IM regulations were first promulgated 
before pipeline operators had experience with potential impact radius 
(PIR) techniques, and incorporating an alternative HCA identification 
method into the original IM regulations using conventional class 
locations was convenient and appropriate. Pipeline operators now have 
over 15 years of experience working with the PIR concept; therefore, 
PHMSA determined using the PIR method for determining MCAs in the 
definition of MCAs is appropriate. PHMSA also disagrees that a separate 
subpart would be preferable and is retaining the requirements for MCA 
assessments in a new Sec.  192.710.
    PHMSA believes the requirement to have a shorter reassessment 
interval is clear and is not modifying that aspect of the rule. PHMSA 
included a requirement for operators to not automatically default to 
the maximum reassessment interval but to establish shorter reassessment 
intervals ``based upon the type anomaly, operational, material, and 
environmental conditions found on the pipeline segment, or as necessary 
to ensure public safety'' when appropriate. Operators have been 
required to perform similar analyses and adjustment of reassessment 
intervals for HCAs since the inception of the IM regulations in 2003 
and should be familiar with this process over 15 years later. PHMSA 
believes that stating the overarching goal of assuring public safety by 
evaluating each pipeline and its circumstances and establishing 
appropriate assessment intervals based on those circumstances provides 
clear intent and is an appropriate approach.
    PHMSA believes that the term ``piggable segment'' is very widely 
understood in the industry and is not including additional definitions 
or regulatory language to expand upon this term. PHMSA understands that 
a pipeline segment might be incapable of accommodating an in-line 
inspection tool for a number of reasons, including but not limited to 
short radius pipe bends or fittings, valves (reduced port) that would 
not allow a tool to pass, telescoping line diameters, and a lack of 
isolation valves for launchers and receivers. Some unpiggable pipelines 
can be made piggable with modest modifications, but others cannot be 
made piggable short of pipe replacement.
    PHMSA understands that a pipeline segment is piggable if it can 
accommodate an instrumented ILI tool without the need for major 
physical or operational modification, other than the normal operational 
work required by the process of performing the inline inspection. This 
normal operational work includes segment pigging for internal cleaning, 
operational pressure and flow adjustments to achieve proper tool 
velocity, system setup such as valve positioning, installation of 
temporary launchers and receivers, and usage of proper launcher and 
receiver length and setup for ILI tools. In addition, a pipeline 
segment that is not piggable for a particular threat because of 
limitations in technology such that an ILI tool is not commercially 
available, might be piggable for other threats. For example, a pipeline 
that is unable to accommodate a crack tool might be able

[[Page 52216]]

to accommodate a conventional MFL or deformation tool, and thus be 
piggable for those threats. Launcher and receiver lengths are not a 
reason for a pipeline to be considered unpiggable, since through a 
minor modification they can be modified to be piggable, and the removal 
of launchers or receivers from the pipeline segment does not make a 
pipeline unpiggable either.

I. Miscellaneous Issues

i. Legal Comments

    The following section discusses industry comments related to legal 
and administrative procedure issues with the proposed rule.
Summary of Public Comment
    Several commenters asserted that the proposed provisions go beyond 
PHMSA's statutory authority provided by the 2011 Pipeline Safety Act. 
Many trade associations and pipeline industry entities stated that 
PHMSA exceeded the congressional mandates in the proposed provisions by 
imposing retroactive recordkeeping requirements and retroactive 
material properties verification requirements. These comments are 
discussed in more detail in their respective sections above.
    Commenters asserted that, in the 2011 Pipeline Safety Act, Congress 
identified specific factors that PHMSA is required to consider when 
proposing regulations per the statutory mandates, including whether 
certain proposed provisions would be economically, technically, and 
operationally feasible, and that the proposed rule did not adequately 
address these factors. For example, AGA expressed concerns that PHMSA 
proposed to adopt NTSB recommendations without independently justifying 
those provisions based on the specific factors required by Congress or 
providing the reasoning behind adopting said recommendations.
    AGA and INGAA also stated that PHMSA did not adequately consider 
the impact that the Natural Gas Act of 1968 would have on 
implementation of the proposed rule. Noting that operators are required 
to obtain permission from FERC before removing pipelines from service 
or replacing pipelines, these commenters stated that obtaining 
permissions could hinder operators from quickly performing required 
tests and repairs. INGAA and AGA also stated that PHMSA did not consult 
with FERC and State regulators about implementation timelines for 
certain provisions, which PHMSA is required to do in accordance with 49 
U.S.C. 60139(d)(3) because gas service would be affected by the 
proposed rule.
PHMSA Response
    PHMSA appreciates the information provided by the commenters 
regarding the statutory authority for the proposed rule. With regard to 
the comments about imposing retroactive recordkeeping requirements and 
retroactive material properties verification requirements, PHMSA 
explained in this document that the final provisions of this rule are 
prospective and do not create retroactive requirements. This topic is 
discussed in more detail in the respective sections about recordkeeping 
and material properties verification.
    Pertaining to PHMSA's broader authority, Congress has authorized 
the Federal regulation of the transportation of gas by pipeline in the 
Pipeline Safety Laws (49 U.S.C. 60101 et seq.) and established the 
current framework for regulating pipelines transporting gas in the 
Natural Gas Pipeline Safety Act of 1968, Public Law 90-481. Through 
these laws, Congress has delegated the DOT the authority to develop, 
prescribe, and enforce minimum Federal safety standards for the 
transportation of gas, including natural gas, flammable gas, or toxic 
or corrosive gas, by pipeline. As required by law, PHMSA has considered 
whether the provisions of this rule are economically, technically, and 
operationally feasible and has provided relevant analysis in the 
Regulatory Impact Analysis and preamble of this rule.
    In accordance with section 23 of the 2011 Pipeline Safety Act, 
PHMSA consulted with the Federal Energy Regulatory Commission and State 
regulators as appropriate to establish the timeframes for completing 
MAOP reconfirmation. As a part of this consultation, PHMSA accounted 
for potential consequences to public safety and the environment while 
also accounting for minimal costs and service disruptions. Furthermore, 
PHMSA will note that both a FERC member and a NAPSR member are on the 
GPAC, providing both input and positive votes that the provisions were 
technically feasible, reasonable, cost-effective, and practicable if 
certain changes were made. As previously discussed, PHMSA has taken the 
GPAC's input into consideration when drafting this final rule and made 
the according changes to the provisions.

I. Miscellaneous Issues

ii.--Records

1. Summary of PHMSA's Proposal
    Many pipeline 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 and PHMSA 
data is obtained through testing and inspection under the existing IM 
requirements. Section 192.917(b) requires operators to gather pipeline 
attribute data as listed in ASME/ANSI B31.8S--2004 Edition, section 4, 
table 1. ASME/ANSI B31.8S--2004 Edition, section 4.1 states:
    ``Pipeline operator procedures, operation and maintenance plans, 
incident information, and other pipeline operator documents specify and 
require collection of data that are suitable for integrity/risk 
assessment. Integration of the data elements is essential in order to 
obtain complete and accurate information needed for an integrity 
management program. Implementation of the integrity management program 
will drive the collection and prioritization of additional data 
elements required to more fully understand and prevent/mitigate 
pipeline threats.''
    However, despite this requirement, 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. Therefore, PHMSA proposed amendments to 
the records requirements for part 192, specifically under the general 
recordkeeping requirements, class location determination records, 
material mechanical property records, pipe design records, pipeline 
component records, welder qualification records, and the MAOP 
reconfirmation provisions.
2. Summary of Public Comment
    Several commenters provided input on the proposed amendments to the 
records requirements for part 192. Several public interest groups, 
including Pipeline Safety Coalition and PST, supported the increased 
emphasis on recordkeeping requirements, stating that the requirements 
are a proactive response to NTSB recommendations and are common-sense 
business best practices.
    Several commenters opposed the proposed provisions providing 
general recordkeeping requirements for part 192. Commenters asserted 
that these proposed provisions apply significant new recordkeeping 
requirements on operators by requiring that operators

[[Page 52217]]

document every aspect of part 192 to a higher and impractical standard 
than before. Commenters also stated that the proposed recordkeeping 
requirements appear to be retroactive and stated that it would be 
inappropriate to require operators to document compliance in cases 
where there have not been requirements to document or retain records in 
the past. Commenters also asserted that the Pipeline Safety Laws at 49 
U.S.C. 60104(b) prohibits PHMSA from applying new safety standards 
pertaining to design, installation, construction, initial inspection, 
and initial testing to pipeline facilities already existing when the 
standard is adopted, and that PHMSA does not have the authority to 
apply these requirements retroactively. These commenters suggested that 
even the recordkeeping requirements in these non-retroactive subparts 
could not be changed under PHMSA's current authority. Subsequently, 
commenters requested that PHMSA confirm that the proposed general, 
material, pipe design, and pipeline component recordkeeping 
requirements would not apply to existing pipelines and that 
recordkeeping requirements for the qualification of welders and 
qualifying plastic pipe joint-makers would not apply to completed 
pipeline projects.
    Additionally, several commenters also requested that PHMSA clarify 
that many of the proposed recordkeeping requirements apply only to gas 
transmission lines. AGA also expressed concern regarding the proposed 
reference to material properties verification requirements in the 
proposed general recordkeeping requirements, which, as written, would 
also require distribution pipelines without documentation to comply 
with the proposed material properties verification requirements.
    Many commenters opposed the proposed application of the term 
``reliable, traceable, verifiable, and complete'' in part 192 beyond 
the requirements for MAOP records, and AGA recommended the deletion of 
``reliable, traceable, verifiable and complete'' from proposed 
provisions under MAOP reconfirmation. Similarly, other commenters, 
including INGAA, recommended omitting ``reliable'' from the phrase and 
provided a suggested definition for ``traceable, verifiable, and 
complete'' records. Additionally, commenters opposed the use of this 
term in the general recordkeeping requirements at Sec.  192.13, stating 
that it would apply a new standard of documentation to part 192. Citing 
a 2012 PHMSA Advisory Bulletin in which PHMSA stated that verifiable 
records are those ``in which information is confirmed by other 
complementary, but separate, documentation,'' INGAA requested that 
PHMSA acknowledge that a stand-alone record will suffice and a 
complementary record is only necessary for cases in which the operator 
is missing an element of a traceable or complete record.\74\ INGAA also 
provided examples of records that they believed to be acceptable, and 
requested that PHMSA includes these examples in the final preamble.
---------------------------------------------------------------------------

    \74\ https://www.phmsa.dot.gov/regulations-fr/notices/2012-10866; 77 FR 26822; May 7, 2012, ``Pipeline Safety: Verification of 
Records.''
---------------------------------------------------------------------------

    Several commenters also opposed the proposed Appendix A to part 192 
that summarizes the records requirements within part 192 and requested 
that it be eliminated, stating that Appendix A goes beyond summarizing 
the existing records requirements and introduces several new 
recordkeeping requirements and retention times. Commenters also 
asserted that Appendix A should not be retroactive. Some commenters 
supported the inclusion of Appendix A, saying that it is a much-needed 
clarification of record requirements and retention. Noting that the 
title of Appendix A suggests that it is specific to gas transmission 
lines but that it does include some record retention intervals for 
distribution lines, NAPSR recommended that Appendix A be expanded to 
include records and retention intervals for all types of pipelines. 
Many commenters requested that PHMSA clarify that the proposed changes 
to Appendix A apply only to gas transmission lines.
    Some commenters also opposed the newly proposed recordkeeping 
requirements for pipeline components at Sec.  192.205. Commenters, 
including Dominion East Ohio, stated that PHMSA should exclude pipeline 
components less than 2 inches in diameter, as these small components 
are often purchased in bulk with pressure ratings and manufacturing 
specifications only printed on the component or box. They further 
stated that in doing this, PHMSA would be consistent with its proposed 
material properties verification requirements. Another commenter stated 
that these requirements should be eliminated because they are 
duplicative of the current requirements for establishing and 
documenting MAOP at Sec.  192.619(a)(1).
    Some commenters also opposed the proposed recordkeeping 
requirements regarding qualifications of welders and welding operators 
and qualifying persons to make joints in Sec. Sec.  192.227 and 
192.285, stating that keeping these records for the life of the 
pipeline is not needed, nor are they necessary for the establishment of 
MAOP.
    Issues related to records were discussed during all of the GPAC 
meetings in various capacities. At the meeting in January 2017, several 
issues were discussed, including: broad records guidance in a general 
duties clause might be a good idea in theory but might cause unintended 
consequences, and they discussed the advisability of addressing 
necessary record components individually in the context of specific 
code sections.
    The GPAC discussed the proposed addition of ``reliable'' to the 
phrase ``traceable, verifiable, and complete'' (TVC) record in the 
proposed rule. The ``TVC'' standard was recommended by the NTSB 
following the PG&E incident. Changing that standard could potentially 
derail work being done by operators to meet that traceable, verifiable, 
and complete record standard.
    The GPAC also discussed PHMSA's statutory authority to impose the 
proposed recordkeeping requirements, even in subparts that are 
retroactive, because PHMSA is not requiring particular types of design, 
installation, construction, etc., but is requiring that operators keep 
records relevant to current operation.
    At the GPAC meeting on June 6, 2017, the GPAC discussed the 
proposed recordkeeping requirements for the qualification of welders 
and welding operators as well as the qualification of persons making 
joints on plastic pipe systems. Specifically, the discussion revolved 
around whether the recordkeeping requirements should be for the life of 
the pipeline, as proposed in the NPRM, or whether it should be for 5 
years. Certain members believed it should be a 5-year requirement to be 
consistent with other operator qualification requirements, and other 
members believed that a 5-year requirement would be adequate due to the 
``bathtub curve'' phenomenon where pipelines are more likely to fail 
early or late in their service history. Therefore, having the records 
for welding qualification within that early period would be sufficient.
    Following that discussion, the committee recommended that PHMSA 
modify the proposed rule to delete the word ``reliable'' from the 
records standard to now read ``traceable, verifiable, and complete'' 
wherever that standard is used; clarify that documentation be required 
to substantiate the current class location under Sec.  192.5(d); and 
modify the recordkeeping provisions related to the

[[Page 52218]]

qualification of welders and the qualification of persons joining 
plastic pipe to include an effective date and change the retention 
period of the necessary records to 5 years.
    At the March 2, 2018, meeting, the GPAC recommended that PHMSA 
withdraw the general duty recordkeeping requirement at Sec.  192.13(e) 
and Appendix A; modify the recordkeeping requirements for pipeline 
components to clarify they apply to components greater than 2 inches in 
nominal diameter; and revise the requirements related to material, pipe 
design, and pipeline component records to clarify the effective date of 
the requirements.
    At the meeting on March 27, 2018, the GPAC recommended that PHMSA 
provide guidance in the preamble regarding what constitutes a 
traceable, verifiable, and complete record. Further, the GPAC 
recommended PHMSA clarify that the MAOP recordkeeping requirements in 
the MAOP establishment section at Sec.  192.619(f) apply only to 
onshore, steel, gas transmission pipelines, and that they only apply to 
the records needed to demonstrate compliance with paragraphs (a) 
through (d) of the section. The GPAC suggested PHMSA could remove 
examples of acceptable MAOP documents from the rule and include that 
listing in the preamble of the final rule and through guidance 
materials.
    The GPAC also recommended that PHMSA clarify that the MAOP 
recordkeeping requirements are not retroactive, that existing records 
on pipelines installed prior to the rule must be retained for the life 
of the pipeline, that pipelines constructed after the effective date of 
the rule must make and retain the appropriate records for the life of 
the pipeline, and that MAOP records would be required for any pipeline 
placed into service after the effective date of the rule. Further, the 
GPAC recommended PHMSA revise the rule by changing other sections, 
including Sec. Sec.  192.624 and 192.917, to require when and for which 
pipeline segments missing MAOP records would need to be verified in 
accordance with the MAOP reconfirmation and material properties 
verification requirements of the rulemaking.
3. PHMSA Response
    PHMSA appreciates the information provided by the commenters 
regarding the proposed records requirements. After considering these 
comments and as recommended by the GPAC, PHMSA is modifying the rule to 
withdraw the proposed Sec.  192.13(e) and Appendix A to avoid possible 
confusion regarding recordkeeping requirements. Also, whenever new 
recordkeeping requirements are included, PHMSA modified the rule to 
clarify that the new requirements are not retroactive. To the degree 
that operators already have such records, they must retain them. 
Operators must retain records created while performing future 
activities required by the code.
    In addition to these general modifications, with regard to specific 
records requirements, PHMSA is modifying the rule as follows: (1) In 
Sec.  192.5(d), operators must retain records documenting the current 
class location (but not historical class locations that no longer apply 
because PHMSA agrees they are not necessary). (2) In Sec.  192.67, the 
rule is being modified to delete reference to ``original steel pipe 
manufacturing records'' to avoid retroactivity concerns, add wall 
thickness and seam type to clarify that this manufacturing information 
must be recorded, and include an effective date to eliminate 
retroactivity concerns. (3) In Sec.  192.205, records for components 
are only required for components greater than 2 inches (instead of 
greater than or equal to 2 inches) (see Section III(A)(i)(3)). (4) In 
Sec.  192.227, records demonstrating each individual welder 
qualification must be retained for a minimum of 5 years because PHMSA 
believes 5 years of welder qualification records are sufficient to 
evaluate whether systemic issues are present upon inspection and at the 
start-up of the pipeline. (5) In Sec.  192.285, records demonstrating 
plastic pipe joining qualifications at the time of pipeline 
installation in accordance must be retained for a minimum of 5 years 
because PHMSA believes 5 years of records are sufficient to evaluate 
whether systemic issues are present upon inspection and at the start-up 
of the pipeline. (6) In Sec.  192.619, PHMSA clarified that new 
recordkeeping for MAOP only apply to onshore, steel, gas transmission 
pipelines. In addition, PHMSA deleted the sentence with examples of 
records that establish the pipeline MAOP, which include, but are not 
limited to, design, construction, operation, maintenance, inspection, 
testing, material strength, pipe wall thickness, seam type, and other 
related data to prevent redundancies in the regulations as this list is 
maintained in Sec.  192.607.
    PHMSA notes that the recordkeeping requirements in this final rule 
under Sec. Sec.  192.67, 192.127, 192.205, and 192.227(c) applicable to 
gas transmission pipelines will apply to offshore gathering pipelines 
and Type A gathering pipelines as well. In accordance with this final 
rule's requirements, operators of such pipelines must keep any of the 
pertinent records they have upon this rule's issuance, and they must 
retain any records made when complying with these requirements 
following the publication of this rule. PHMSA notes that the 
requirements for creating records in Sec. Sec.  192.67, 192.127, 
192.205, and 192.227(c) are forward-looking requirements. However, and 
in accordance with this final rule, operators must retain any records 
they currently have for their pipelines. Any records generated through 
the course of operation, including, most notably, records generated by 
the material properties verification process at Sec.  192.607, must 
also be retained by operators for the life of the pipeline.
    As requested by the GPAC, PHMSA considered moving Sec.  192.619(e) 
to be a subsection of Sec.  192.619(a) and considered referencing Sec.  
192.624 in Sec.  192.619(a). However, PHMSA is retaining the proposed 
paragraph (e) in the final rule and the reference to Sec.  192.624 
within Sec.  192.619(e) because it more clearly requires pipeline 
segments that meet any of the applicability criteria in Sec.  
192.624(a) must reconfirm MAOP in accordance with Sec.  192.624, even 
if they comply with Sec.  192.619(a) through (d). This also avoids the 
potential for conflict if this requirement were to be placed in a 
paragraph that applies to gathering lines and distribution lines. It 
also makes it clear that pipeline segments with MAOP reconfirmed under 
Sec.  192.624 are not required to comply with Sec.  192.619(a) through 
(d).
    Lastly, throughout this final rule, PHMSA is deleting the word 
``reliable'' from the records standard to now read ``traceable, 
verifiable, and complete'' wherever that description is used. PHMSA 
issued advisory bulletins ADB 12-06 on May 7, 2012 (77 FR 26822) and 
ADB 11-01 on January 10, 2011 (76 FR 1504). In these advisory 
bulletins, PHMSA provided clarification and guidance that all documents 
are not records and provided additional information on the definition 
and standard for records. For a document to be a record, it must be 
traceable, verifiable, and complete. PHMSA provides further explanation 
of these concepts below.
    Traceable records are those which can be clearly linked to original 
information about a pipeline segment or facility. Traceable records 
might include pipe mill records, which include mechanical and chemical 
properties; purchase requisition; or as-built documentation indicating 
minimum pipe yield

[[Page 52219]]

strength, seam type, wall thickness and diameter. Careful attention 
should be given to records transcribed from original documents as they 
may contain errors. Information from a transcribed document, in many 
cases, should be verified with complementary or supporting documents.
    Verifiable records are those in which information is confirmed by 
other complementary, but separate, documentation. Verifiable records 
might include contract specifications for a pressure test of a pipeline 
segment complemented by pressure charts or field logs. Another example 
might include a purchase order to a pipe mill with pipe specifications 
verified by a metallurgical test of a coupon pulled from the same 
pipeline segment. In general, the only acceptable use of an affidavit 
would be as a complementary document, prepared and signed at the time 
of the test or inspection by a qualified individual who observed the 
test or inspection being performed.
    Complete records are those in which the record is finalized as 
evidenced by a signature, date or other appropriate marking such as a 
corporate stamp or seal. For example, a complete pressure testing 
record should identify a specific segment of pipe, who conducted the 
test, the duration of the test, the test medium, temperatures, accurate 
pressure readings, and elevation information as applicable. An 
incomplete record might reflect that the pressure test was initiated, 
failed and restarted without conclusive indication of a successful 
test. A record that cannot be specifically linked to an individual 
pipeline segment is not a complete record for that segment. Incomplete 
or partial records are not an adequate basis for establishing MAOP or 
MOP. If records are unknown or unknowable, a more conservative approach 
is indicated.
    For example, a mill test report must be traceable, verifiable, and 
complete, which is a typical record for pipelines. For the mill test 
report to be traceable it would need to be dated in the same time frame 
as construction or have some other link relating the mill record to the 
material installed in the pipeline, such as a work order or project 
identification. For the mill test report to be verified, it would need 
to be confirmed by the purchase or project specification for the 
pipeline or the alignment sheet with consistent information. Such an 
example would be verified by independent records. For the mill test 
report to be complete, it must be signed, stamped, or otherwise 
authenticated as a genuine and true record of the material by the 
source of the record or information, in this example it could be the 
pipe mill, supplier, or testing lab.
    Another common record is a pressure test record, which must be 
traceable, verifiable, and complete. For the pressure test record to be 
traceable, it would need to identify a specific and unique segment of 
pipe that was tested (such as mileposts, survey stations, etc.) or have 
some other link relating the pressure test to the physical location of 
the test segment, such as a work order, project identification, or 
alignment sheet. For the pressure test record to be verified, it would 
need to be confirmed by the purchase or project specification for the 
pipeline or the alignment sheet with consistent information. Such an 
example would be verified by independent records. For the pressure test 
record to be complete, it should identify a specific segment of pipe, 
who conducted the test, the duration of the test, the test medium, 
temperatures, accurate pressure readings, elevation information, and 
any other information required by Sec.  192.517, as applicable. An 
incomplete record might reflect that the pressure test was initiated, 
failed and restarted without conclusive indication of a successful 
test.

I. Miscellaneous Issues

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

NPRM Assumptions/Proposals
    U.S. Code, title 49, chapter 601, section 60102 specifies that the 
U.S. Department of Transportation (U.S. DOT), when prescribing any 
pipeline safety standard, shall consider relevant available gas and 
hazardous liquid pipeline safety information, environmental 
information, the appropriateness of the standard, and the 
reasonableness of the standard. In addition, the U.S. DOT must, based 
on a risk assessment, evaluate the reasonably identifiable or estimated 
benefits and costs expected to result from implementation or compliance 
with the standard. PHMSA prepared a preliminary regulatory impact 
analysis (PRIA) to fulfill this statutory requirement for the proposed 
rule and a new regulatory impact analysis (RIA) for this final rule. In 
addition, PHMSA's Environmental Assessment (EA) is prepared in 
accordance with NEPA, as amended, and the Council on Environmental 
Quality (CEQ) regulations for implementing NEPA (40 CFR parts 1500-
1508). When an agency anticipates that a proposed action will not have 
significant environmental effects, the CEQ regulations provide for the 
preparation of an EA to determine whether to prepare an environmental 
impact statement or finding of no significant impact.
Summary of Public Comment
Cost Impacts
    Several commenters provided input on the cost analysis conducted in 
the PRIA, providing comments on the structure, assumptions, and unit 
costs in the PRIA as well as on the lack of accounting for impacts such 
as the abandonment of pipelines and the cost increase to electricity 
ratepayers.
    Some public interest groups provided input on the cost analysis in 
the PRIA. EDF stated that the PRIA reasonably addressed uncertainty and 
lack of information surrounding certain key data assumptions. EDF 
further stated that the PRIA aligned with Office of Management and 
Budget guidance on the development of regulatory analysis for 
rulemakings. They stated that PHMSA used conservative values when 
making best professional judgments. PST asserted that the costs 
included in the PRIA for reconfirmation of MAOP, data gathering, record 
maintenance, and data integration for lines subject to the IM 
provisions result from the current IM regulations and practices and 
should not be attributed to this rulemaking. They further stated that 
the PRIA should be amended to remove these costs related to lines 
within HCAs.
    Several trade associations and industry pipeline entities provided 
input on the assumptions, methodology, and unit costs used in the PRIA, 
stating that PHMSA underestimated the cost of complying with the 
proposed regulations. AGA stated that the organization of the PRIA by 
``topic areas'' made it difficult to evaluate the cost estimates of the 
various provisions of the rule and requested that PHMSA provide a RIA 
with the final rule that addresses each regulatory section as organized 
in the preamble. Many commenters, including INGAA, AGA, AGL Resources, 
and Piedmont, stated that the PRIA underestimated the cost impacts of 
increased material properties verification, recordkeeping, and MAOP 
reconfirmation requirements. AGL Resources asserted that complying with 
the proposed record requirements would involve increased labor and 
investment costs that should be quantified in the final RIA. AGA stated 
that it was unclear whether or how the PRIA incorporated material 
properties verification costs related to material documentation, plan 
creation, revisions, and testing. NYSEG asserted that the PRIA 
underestimated the cost impact of the proposed rule on smaller local

[[Page 52220]]

distribution companies with combined transmission and distribution 
systems and estimated that they would have to perform IM elements on 8 
times the mileage currently in their IM program. Lastly, INGAA provided 
a higher cost for MAOP confirmation than was estimated in the PRIA due 
in large part to their assumption that industry would continue to rely 
on pressure testing, as they asserted that the proposed methods for ILI 
and ECA are not feasible.
    INGAA, AGA, and API submitted detailed cost analyses to the 
rulemaking docket, while many other commenters (approximately 40) 
provided estimated unit costs for various provisions of the proposed 
rule that were generally higher than the unit costs used in the PRIA. 
For example, Southwest Gas stated that the costs included in the PRIA 
for options such as ILI and pressure testing were not representative of 
the costs to their system. With regard to the cost of integrity 
assessments, BG&E stated that it would cost them over $1 million per 
year to perform integrity assessments on the additional 100 miles of 
MCA transmission pipelines, a total which equates to a higher cost per 
mile estimate than was used in the PRIA. Additionally, New Mexico Gas 
Co. stated that the proposed rule would cost their company $5.6 million 
per year to perform integrity assessments on 528 miles of MCA 
transmission pipe. Vectren estimated the impact to its transmission 
system would cost $22 million annually. Lastly, PG&E stated that their 
forecasted costs to implement the proposed rule are significantly 
higher than the estimates in the PRIA. PG&E provided a comparison of 
the PRIA costs with their expected expenditures to comply with many 
provisions in the proposed rule. They projected the cost of compliance 
would require an upfront investment of $578 million in addition to $222 
million per year (as well as a reoccurring cost of $30 million every 7 
years) and stated that, comparatively, the PRIA estimates a present 
value annualized cost of $47 million per year.
    Some stakeholders provided input on the estimated number of miles 
that PHMSA used to determine the regulatory impact of the provisions in 
the proposed rule. For example, INGAA stated that it assumed the 
mileage estimated by PHMSA for estimation of MAOP confirmation, 
material properties verification, and integrity assessments outside 
HCAs to be accurate with the addition of reportable in-service 
incidents since last pressure test data. INGAA also asserted that the 
mileage estimated for MCA transmission pipes should be done on the per-
foot basis instead of on the per-mile basis because these pipes are 
likely to be an aggregation of short pipeline segments that are 1 mile 
or shorter in length. The North Dakota Petroleum Council asserted that 
proposed changes in the definition of onshore gathering lines would 
dramatically increase the number of miles of regulated gathering wells 
beyond the mileage estimates in the PRIA.
    Some commenters asserted that the financial impact of the proposed 
rule would be immense and that, because operators would not be able to 
bear these costs alone, they would likely pass the costs on to the 
ratepayers. For example, APGA stated that all of their member utilities 
purchase gas and pay transportation charges to transmission pipelines 
to deliver gas from the producer to the utility. They asserted that 
ratepayers would pay for the costs that would be incurred by their 
transmission suppliers to comply with this rule. Similarly, Indiana 
Utility Regulatory Commission requested that PHMSA consider the costs 
to ratepayers in its cost analysis. Other commenters stated that this 
rule could force operators to take significant portions of their 
pipelines out of service while they are brought into compliance and 
that the PRIA failed to recognize that FERC requires interstate natural 
gas pipelines operators to provide demand charge credits to customers 
when service is disrupted.
    Some commenters stated that the proposed rule may cause pipeline 
abandonment and that these impacts should be considered in the final 
RIA. Boardwalk Pipeline stated that if a pipe is no longer economic to 
operate, but FERC does not grant abandonment authority, a pipeline 
company would be forced to either operate a pipeline that may not meet 
PHMSA standards or undertake expensive replacement projects. Boardwalk 
Pipeline further stated that while operators may seek to recover the 
costs of replacement projects through rate increases, in a competitive 
pipeline market where operators are forced to discount their pipeline 
rates in order to retain customers, these costs might be too great to 
recover. Similarly, the Independent Petroleum Association of America 
stated that the PRIA failed to account for the costs that could be 
incurred by operators if pipeline infrastructure is abandoned because 
the cost that would be required to comply with the rule would 
necessitate this abandonment. The Public Service Commission of West 
Virginia suggested that, should operators abandon wells and pipelines 
due to the requirements of this proposed rule, it could cause an 
environmental and economic liability for State regulators if operators 
abandon wells and pipelines without proper clean up.
    Several commenters expressed concern that PHMSA's cost-benefit 
analysis does not meet the requirements established by the 2011 
Pipeline Safety Act and the Administrative Procedures Act (APA). Trade 
associations stated that the PRIA does not fulfill PHMSA's statutory 
obligations because it omits relevant costs, relies on incorrect 
assumptions, and contains multiple inconsistencies. INGAA asserted that 
the PRIA does not comply with the APA because the finding in the PRIA 
that the proposed benefits outweigh the costs is contingent on an 
underestimation of the costs of the proposed rule. INGAA also noted 
that flawed cost-benefit analysis can be grounds for courts to reject 
agency rulemakings. INGAA asserted that the proposed rulemaking does 
not comply with the Paperwork Reduction Act (PRA), because PHMSA's 
estimate of the information collection burden did not include the costs 
of these additional recordkeeping requirements for transmission 
pipeline operators.
Benefit Estimates
    PHMSA also received comments on the benefits associated with the 
proposed rule. Physicians for Social Responsibility expressed their 
support of the proposed rule and the analysis of reduced accidents and 
increased worker safety in the PRIA. Additionally, Physicians for 
Social Responsibility stated that many harmful air pollutants, such as 
nitrous oxide, sulfur dioxide, particulate matter, formaldehyde, and 
lead, are all associated with gas pipelines and compressor stations. 
They further stated that this rule would help reduce or mitigate this 
pollution and that these public health benefits should be accounted for 
in the benefits calculations.
    Other commenters, including AGA and INGAA, stated that PHMSA 
overestimated the damage caused by incidents in the quantification of 
benefits in the PRIA. AGA stated that PHMSA allowed one major incident 
to skew the data in their benefits analysis and proposed that PHMSA 
adopt a new approach to quantify the benefits of reduced accidents. 
INGAA stated that using data from the past 13 years skewed the results 
and that the most recent 5 years of incident history would more 
reasonably reflect positive developments in pipeline safety, given that 
significant developments in pipeline safety have occurred within this 
time period.

[[Page 52221]]

    Several commenters provided input on the proposed use of the social 
cost of carbon and the social cost of methane in the PRIA. EDF and 
National Resource Defense Council supported the use of the social costs 
of carbon and methane methodology in the PRIA. However, these 
commenters stated that the estimates for social costs of carbon and 
methane were likely too conservative and that the values should be 
higher than those used in the PRIA. These commenters stated that PHMSA 
should encourage the Interagency Working Group on Social Cost of Carbon 
to update regularly the social cost of carbon and social cost of 
methane as new economic and scientific information emerges. API stated 
that the proposed use of the social cost of methane to calculate the 
benefits of emissions reductions was flawed due to the discount rates 
used by PHMSA. They asserted that PHMSA used low discount rates that 
led to a liberal damage estimate. In addition, API and Industrial 
Energy Consumers of America asserted that the social cost of carbon 
values used by PHMSA inappropriately impose global carbon costs on 
domestic manufacturers, which damages the industry's ability to compete 
internationally. AGA stated that the process used to develop the social 
cost of methane values in the PRIA did not undergo sufficient expert 
and peer review. INGAA stated that PHMSA overestimated the amount of 
greenhouse gas emissions that the rule would reduce.
Environmental Impacts
    Several commenters noted that the 2011 Pipeline Safety Act mandates 
that PHMSA consider the environmental impacts of proposed safety 
standards. Citizen groups stated that the proposed regulation fulfills 
this statutory obligation and is a step forward in reducing methane 
emissions from natural gas pipelines. Multiple citizen groups 
emphasized the consequences of climate change, the high global warming 
potential of methane, and the responsibility of natural gas systems for 
a significant portion of U.S. methane emissions. Citizen groups 
underlined the importance of regulating methane leaks and considering 
methane's climate implications in natural gas regulations. The Lebanon 
Pipeline Awareness Group addressed local environmental impacts, 
requesting that pipelines not be permitted to contaminate agricultural 
soils.
    Trade associations asserted that PHMSA did not fulfill its 
statutory obligation to consider the full environmental impacts of the 
proposed safety standards, suggesting that PHMSA failed to consider 
several topics in the NPRM that would have direct environmental 
impacts. These commenters claimed that certain topics and their 
impacts, including IM clarifications, MAOP reconfirmation, and 
hydrostatic pressure testing, were mischaracterized in the EA, and that 
PHMSA further underestimated the number of excavations that would need 
to be made per the proposal as well as the impacts of procuring and 
disposing of water for hydrostatic tests.
    Trade associations further expressed concerns that, while PHMSA had 
addressed the emissions avoided under the proposed rule, PHMSA had not 
addressed the extent to which the proposed rule would increase 
emissions. AGA and INGAA noted that operators need to purge lines of 
natural gas before conducting hydrostatic tests or removing pipelines 
from service for replacement or repair. These commenters stated that 
the proposed regulation would increase methane emissions by increasing 
the number of hydrostatic tests, pipeline replacements, and pipeline 
repairs required and asserted that the EA did not take the increased 
emissions from these blowdowns into account. INGAA asserted that not 
considering these methane emissions constituted a violation of the 2011 
Pipeline Safety Act and failure to ``engage in reasoned decision 
making.'' INGAA also suggested that the methane emissions resulting 
from this rulemaking would run counter to President Obama's goals of 
reducing methane emissions.
    EDF and PST commissioned a study from M.J. Bradley & Associates 
(MJB&A) that calculated the extent to which the proposed rule would 
result in blowdown emissions. MJB&A found that potential methane 
emissions resultant from the proposed rule would increase annual 
methane emissions from natural gas transmission systems by less than 
0.1 percent and increase annual methane emissions from transmission 
system routine maintenance by less than one percent. MJB&A also noted 
five mitigation methods that if implemented, could decrease blowdown 
emissions by 50 to 90 percent.\75\ MBJ&A calculated that the societal 
benefits of methane reduction outweighed the mitigation costs for all 
mitigation options considered. Based on this study, EDF asserted that 
while the marginal increase in emissions from the proposed rule would 
be small, the total emissions from blowdowns would nonetheless be 
significant. They stated that PHMSA should require operators to select 
and implement one of the mitigation options and report to PHMSA 
information about their blowdown events, such as the mitigation option 
selected and the amount of product lost due to blowdowns required by 
the proposed rule. EDF also stated that if operators do not mitigate 
blowdown emissions, they should be required to provide an engineering 
or economic analysis demonstrating why mitigation is deemed infeasible 
or unsafe.
---------------------------------------------------------------------------

    \75\ The methods are (1) gas flaring; (2) pressure reduction 
prior to blowdown with inline compressors; (3) pressure reduction 
prior to blowdown with mobile compressors; (4) transfer of gas to a 
low-pressure system; and (5) reducing the length of pipe requiring 
blowdown by using stopples.
---------------------------------------------------------------------------

    AGA stated that the EA did not address other environmental impacts 
resultant from hydrostatic pressure testing. AGA noted two anticipated 
water-related impacts: (1) Hydrostatic pressure testing's water demand 
could aggravate water scarcity in already water-scarce environments, 
and (2), the water used in hydrostatic tests could introduce 
contaminants if disposed on-site (or be very expensive to transport to 
off-site disposal). AGA explained that wastewater from hydrostatic 
tests could include hydrocarbon liquids and solids, chlorine, and 
metals.
    AGA also asserted that the EA did not adequately consider the land 
disturbances that could result from the proposed hydrostatic testing 
requirements, nor did it consider that performing inline inspections 
and modifying pipelines to accommodate inline inspection tools would 
generate waste and disturb natural lands. AGA explained that operators 
must clean pipelines prior to conducting inline inspections or 
modifying pipelines for inline inspection tools and that this cleaning 
could produce large volumes of pipeline liquids, mill scale, oil, and 
other debris. AGA expressed concerns that the proposed EA did not 
discuss these environmental impacts associated with requiring MAOP 
confirmation, given that PHMSA anticipates that most affected pipelines 
would verify MAOP using ILI and pressure testing.
    AGA also provided input on the local environmental impacts of the 
proposed increased testing and inspection. AGA expressed concerns that 
the EA had (1), underestimated the quantity of excavations that would 
be required under the proposed rule, and (2), inadequately assessed the 
environmental impacts of those excavations. AGA asserted that the EA 
had insufficiently considered the extent to which more excavations 
would generate water and soil waste. AGA also suggested that the 
proposed rule may

[[Page 52222]]

induce operators to modify or replace pipelines and that these 
modifications and replacements may affect land beyond existing rights 
of way. AGA asserted that this additional land area should be 
considered in the EA.
    Trade associations raised other technical issues regarding the EA. 
AGA expressed concerns that PHMSA provided insufficient information 
about methods used to calculate values in the EA and that this 
insufficient documentation interfered with stakeholders' ability to 
provide comments on the values that PHMSA chose. INGAA asserted that 
the proposed rule fell short of several legal obligations under NEPA, 
stating that the EA does not provide the required ``hard look'' at 
environmental impacts, that the EA does not adequately discuss the 
indirect and cumulative effects of the proposed rule, and that the 
purpose and need statement in the EA do not fulfill NEPA instructions. 
INGAA also expressed concern that PHMSA did not consider sufficient 
regulatory alternatives, stating that the EA considered solely the 
proposed rule, one regulatory alternative, and the no action 
alternative. INGAA stated that given the many provisions of the 
proposed rule, this approach was too limited.
Other Impacts
    Some trade associations and pipeline industry entities provided 
input that the PRIA failed to account for the indirect effects of 
operators shifting resources to comply with the proposed rule. For 
example, AGA stated that the PRIA did not consider the potential 
indirect impacts the rule might impose on distribution lines. They 
asserted that the magnitude and prescriptiveness of the proposed rule 
would require distribution companies with intrastate transmission and 
distribution assets to reassign their limited resources to transmission 
lines.
    Some commenters stated that PHMSA did not consider that the 
proposed rule would divert resources away from voluntary safety 
programs their companies are initiating, stating that these voluntary 
safety measures would be scaled back because of the proposed rule. For 
example, AGA stated that accelerated pipe replacement programs that 
replace aging cast iron, unprotected steel pipe, and vintage plastic 
pipe, would lose resources as operators shift staff and capital to 
comply with the proposed rule. They further asserted that failing to 
replace these pipes would delay reductions in methane emissions from 
old, leaky pipes.
PHMSA Response
Cost Impacts
    PHMSA has reviewed the comments related to the RIA for the proposed 
rule and has revised the final analysis consistent with the final rule 
and in consideration of the comments. PHMSA addressed the comments 
received on the RIA in two key ways. First, PHMSA revised many of the 
requirements in the final rule, including (a) revising or clarifying 
that the final provisions do not apply to gas distribution or gas 
gathering pipelines; (b) revising MAOP reconfirmation requirements for 
grandfathered pipelines to include only those lines with MAOP greater 
than or equal to 30 percent SMYS; (c) streamlining the process for 
operators to use an alternative technology for MAOP reconfirmation; (d) 
removing the term ``occupied sites'' in the MCA definition; and (e) 
revising the records provisions to remove certain proposed provisions 
and clarifying that the new requirements are not retroactive. These 
changes, as well as others made in the final rule, result in less 
costly and more cost-effective requirements. Second, in response to 
comments received, PHMSA made several revisions to the analysis 
conducted in the RIA for the proposed rule, discussed below. Also, in 
response to comments, PHMSA revised the final RIA to align more closely 
to the preamble organization.
    PHMSA acknowledges the baseline issues associated with establishing 
MAOP, data collection, and other provisions noted in the comments. In 
the final RIA, PHMSA is including estimated incremental costs to 
reconfirm MAOP for lines within HCAs based on a current compliance 
baseline. Attributing compliance to existing pipeline safety 
regulations would reduce both the costs and benefits of the final rule. 
Regarding the comments that the RIA for the proposed rule 
underestimated the cost impacts of material properties verification, 
recordkeeping, and MAOP confirmation, as discussed above, the changes 
to the scope and applicability of the MAOP reconfirmation, data, and 
recordkeeping provisions result in common-sense, cost-effective 
requirements. For example, PHSMA designed the final requirements for 
material properties verification to allow operators the option of a 
sampling program that opportunistically takes advantage of repairs and 
replacement projects to verify material properties simultaneously. The 
final provisions allow, over time, operators to collect enough 
information to gain significant confidence in the material properties 
of pipe subject to this requirement.
    Further, as discussed under the section regarding the material 
properties verification process, the final rule removes the 
applicability criteria of the material properties verification 
requirements and makes a procedure for obtaining pipeline physical 
properties and attributes that are not documented in traceable, 
verifiable, and complete records or for otherwise verifying pipeline 
attributes when required by MAOP reconfirmation requirements, IM 
requirements, repair requirements, or other code sections. Therefore, 
due to the changes made from the proposed rule, the material properties 
verification requirements mandated by section 23 of the 2011 Pipeline 
Safety Act represent a cost savings in comparison to existing 
regulations, although PHMSA has not quantified those savings.
    With regard to the operator-provided cost information or estimates 
of the proposed rule, the commenters' estimates were not transparent 
enough for PHMSA to discern the assumptions and inputs underlying the 
estimates. As a result, PHMSA could not reliably confirm whether the 
cost information accurately reflected the quantity and character of the 
actions required by the proposed rule. To improve the transparency of 
the analysis and address commenters' concerns about PHMSA's reliance on 
best professional judgment in the RIA for the proposed rule, PHMSA 
contacted five vendors of pipeline inspection and testing services to 
obtain updated cost estimates for several unit costs that were based on 
best professional judgement in the RIA for the proposed rule. These 
vendors provided representative incremental costs associated with the 
final rule requirements. In the final RIA, PHMSA used prices provided 
by vendors to estimate unit costs for all MAOP reconfirmation and 
integrity assessment methods, as well as for upgrades to launchers and 
receivers.
    Regarding MAOP reconfirmation specifically, in the RIA for the 
proposed rule PHMSA assumed operators would conduct MAOP reconfirmation 
using either pressure testing or ILI. In the final RIA, based on 
feedback received during a GPAC meeting,\76\ PHMSA assumed that 
operators would reconfirm MAOP using a mix of all six available 
compliance methods.
---------------------------------------------------------------------------

    \76\ GPAC Meeting, March 26-28, 2018. For a transcript of the 
meeting, see https://primis.phmsa.dot.gov/meetings/FilGet.mtg?fil=970.
---------------------------------------------------------------------------

    Additionally, in the final RIA, PHMSA analyzed the requirements for 
MAOP reconfirmation and integrity

[[Page 52223]]

assessments outside HCAs for each operator individually based on the 
information they submitted in their Annual Reports. Based on the 
information in operator Annual Reports and the final rule requirements 
for MAOP reconfirmation, some operators will incur less of an impact 
than indicated by their public comments.
    Regarding the comment that the proposed changes to the definition 
of onshore gathering lines would dramatically increase the number of 
miles of regulated gathering wells beyond the mileage estimates in the 
RIA for the proposed rule, this final rule does not change the 
definition of gathering pipelines.
    With respect to pipelines located within MCAs, PHMSA confirmed the 
analysis of the length of gas transmission pipelines located within 
MCAs in the RIA for the proposed rule by integrating additional spatial 
data from the U.S. Census Bureau, U.S. Geological Survey, Environmental 
Systems Research Institute, and Tele-Atlas North America, Inc. For 
additional details on the MCA GIS analysis, see section 5.7 of the RIA 
for the final rule. This allowed PHMSA to confirm the number of 
impacted miles. Additionally, due to existing state MAOP reconfirmation 
requirements, PHMSA updated the RIA to reflect that impacts in 
California are not attributable to the rule. Lastly, PHMSA presented 
all impacted mileage on a dollar-per-foot basis instead of dollars per 
mile, based on comments received that these pipeline segments are 
likely to be an aggregation of short pipeline segments that are a mile 
or shorter in length.
    Regarding the comment that PHMSA underestimated the cost impact of 
the proposed rule on smaller local distribution companies with combined 
gas transmission and gas distribution systems, PHMSA conducted an 
analysis of the rule's impact on small entities by comparing entity-
level cost estimates to annual entity revenues and identifying entities 
for which annualized costs may exceed 1 percent and 3 percent of 
revenue. As documented in the final Regulatory Flexibility Act (FRFA) 
analysis, PHMSA relied on conservative assumptions in performing this 
sales test, which may overstate, rather than understate, compliance 
costs for small entities. PHMSA found that the final rule will not have 
a significant economic impact on small entities.
    PHMSA does not agree that the final rule requirements constitute a 
significant energy action. PHMSA agrees with the comment that the costs 
would be passed on to ratepayers; however, PHMSA disagrees that these 
costs would be immense. E.O. 13211 requires agencies to prepare a 
Statement of Energy Effects when undertaking certain agency actions if, 
among other criteria, the regulation is expected to see an increase in 
the cost of energy production or distribution in excess of one percent. 
The annualized cost of these requirements represents less than 0.1 
percent of pipeline transportation of natural gas (North American 
Industry Classification System code 486210) industry revenues ($25 
billion), adjusting the 2012 Economic Census value into 2017 dollars 
using the Gross Domestic Product Implicit Price Deflator Index. 
Therefore, in the aggregate it is extremely unlikely that these 
requirements would cause a significant increase in costs that utilities 
would pass on to the ratepayer.
    Available information supports that, in the baseline, operators are 
replacing or abandoning certain pipelines regardless of the 
implementation of this rule as well as taking other actions such as 
making lines piggable.\77\ As discussed above, in the final RIA, PHMSA 
assumed some use of pipe replacement and abandonment as a means of 
operators reconfirming MAOP. However, the costs of replacing 
infrastructure operating beyond the design useful life are not 
attributable to safety regulations and investment in plant, including a 
return on investment, are already recovered through rates.
---------------------------------------------------------------------------

    \77\ PG&E. 2011. ``Pacific Gas And Electric Company's Natural 
Gas Transmission Pipeline Replacement Or Testing Implementation 
Plan.'' California Public Utilities Commission; Consolidated Edison 
Company Of New York. 2016. ``Consolidated Edison Company Of New 
York, Inc. 2017-2019 Gas Operations Capital Programs/Projects.'' New 
York State Department of Public Service. http://documents.dps.ny.gov/public/MatterManagement/CaseMaster.aspx?MatterCaseNo=16-G-0061&submit=Search.
---------------------------------------------------------------------------

    The RIA for the final rule meets all PHMSA's requirements under 
applicable acts and executive orders. The analysis involves estimating 
a baseline scenario and changes under the regulation. PHMSA has used 
its judgement, available data, information, and analytical methods to 
develop an analysis of the baseline and incremental costs and benefits 
under the rule. As discussed above, some costs and benefits may be 
attributable to existing requirements and some may occur in the absence 
of the rule.
Benefits Estimates
    PHMSA agrees that recent data is more reflective of recent 
improvements in pipeline safety and performance relative to current 
standards. For the final RIA, PHMSA used more recent data on pipeline 
incidents from 2010 to 2017 versus the 2003 to 2015 data used in the 
RIA for the proposed rule. PHMSA used the data from 2010 on because 
PHMSA updated its incident reporting methodology in 2010, and this 
period therefore provides the largest available sample of consistently 
reported incident data. Regarding the benefits analysis for the 
preliminary RIA developed for the NPRM potentially being skewed by one 
major incident (the PG&E incident at San Bruno), there is no evidence 
that more serious incidents are not possible in the future in the 
absence of the regulation, and therefore, PHMSA does not exclude this 
incident when qualitatively assessing benefits. At the same time, and 
although PHMSA developed this rule to prevent future, similar 
incidents, PHMSA cannot know with certainty whether a similar incident 
would occur again absent this rulemaking. According to the historical 
record, serious incidents, like the one occurring at San Bruno, occur 
approximately once per decade. For example, on August 19, 2000, a 30-
inch-diameter natural gas transmission pipeline operated by the El Paso 
Natural Gas Company ruptured adjacent to the Pecos River near Carlsbad, 
NM. The released gas ignited and burned for 55 minutes. Twelve persons 
camping near the incident location were killed, and their three 
vehicles were destroyed.\78\ Similarly, on March 23, 1994, a 36-inch-
diameter natural gas transmission pipeline owned and operated by Texas 
Eastern Transmission Corporation ruptured in Ellison Township, NJ. The 
incident caused at least $25 million in damages, dozens of injuries, 
and the evacuation of hundreds.\79\ More detailed data on current 
pipeline integrity in relation to populations and the environment would 
enable more detailed predictions of the benefits of regulations.
---------------------------------------------------------------------------

    \78\ Natural Gas Pipeline Rupture and Fire Near Carlsbad, New 
Mexico, August 19, 2000, Pipeline Accident Report, NTSB/PAR-03/01, 
Washington, DC.
    \79\ Texas Eastern Transmission Corporation Natural Gas Pipeline 
Explosion and Fire, Pipeline Accident Report, NTSB/PAR-95-01, 
Washington, DC.
---------------------------------------------------------------------------

    Due to the speculative nature of predicting the occurrence, 
avoidance, and character of specific future pipeline incidents, in the 
final RIA, PHMSA elected not to quantify the rule's benefits. PHMSA 
uses this approach rather than make highly uncertain predictions about 
both a specific number of future incidents avoided due to the final 
rule, and the character of avoided incidents with respect to effects on 
benefit-analysis endpoints (e.g., fatalities, injuries, evacuation). 
The

[[Page 52224]]

quantified benefits for each provision therefore represent the quantity 
of a given benefit category required to achieve a dollar value equal to 
the provision's compliance cost.
    PHMSA does not have data on harmful air pollutants such as nitrous 
oxide, sulfur dioxide, particulate matter, formaldehyde, and lead 
associated with gas pipelines and compressor stations, or the 
reductions in these pollutants under the rule. Therefore, the analysis 
did not address the environmental costs associated with these 
pollutants. PHMSA did not include estimates of benefits based on the 
social cost of methane for the final rule.
Environmental Impacts
    Regarding the comments stating that the preliminary EA did not 
adequately consider the air emissions that would result from 
hydrostatic pressure testing, inline inspections, excavations, and MAOP 
reconfirmation, PHMSA revised the EA to address this issue. Commenters 
asserted that by increasing the number of hydrostatic tests, pipeline 
replacements, and pipeline repairs required, the proposed provisions 
would increase methane ``blowdown'' emissions that result from the 
required purging of natural gas pipelines before conducting these 
actions. PHMSA revised the EA to include a discussion of the study 
conducted by M.J. Bradley & Associates (MJB&A) \80\ that calculated the 
extent to which the proposed rule would result in blowdown emissions.
---------------------------------------------------------------------------

    \80\ The study was commissioned by EDF and PST and is available 
at http://blogs.edf.org/energyexchange/files/2016/07/PHMSA-Blowdown-Analysis-FINAL.pdf.
---------------------------------------------------------------------------

    MJB&A found that unmitigated blowdown from the miles of 
transmission pipeline that would be required to conduct a MAOP 
determination would release an average of 1,353 metric tons per year of 
methane to the atmosphere for the 15-year compliance period \81\ 
proposed by PHMSA. By comparison, historical unintentional releases 
from natural gas transmission pipelines outside of HCAs with piggable 
lines greater than 30 percent SMYS (a universe of facilities that could 
be subject to MAOP reconfirmation in MCAs) averaged 13,500 metric tons 
per year from 2010 to 2017. These releases were caused by 163 incidents 
that released an average of 663.4 metric tons per incident.\82\
---------------------------------------------------------------------------

    \81\ See Sec.  192.624(b).
    \82\ ``Distribution, Transmission & Gathering, LNG, and Liquid 
Accident and Incident Data.'' Phmsa.Dot.Gov. 2017. https://www.phmsa.dot.gov/data-and-statistics/pipeline/distribution-transmission-gathering-lng-and-liquid-accident-and-incident-data.
---------------------------------------------------------------------------

    Therefore, if the final rule requirements avoided two average 
incidents per year, the rule would not result in any net methane 
releases. MJB&A further stated that the potential methane emissions 
resultant from the NPRM would increase annual methane emissions from 
natural gas transmission systems by less than 0.1 percent and increase 
annual methane emissions from transmission system routine maintenance/
upsets by less than one percent. Given these factors, PHMSA does not 
believe that the final rule will result in a significant, if any, 
increase in methane releases.
    In response to comments, PHMSA revised the EA to also include a 
discussion of water-related impacts resulting from hydrostatic pressure 
testing as well as waste generation land disturbances from hydrostatic 
pressure testing and inline inspections. Operators must conduct all 
waste and wastewater disposal activities in accordance with federal, 
state, and local regulations and permit requirements, and the final 
rule requires processes and procedures in which pipeline operators are 
already familiar with respect to pipeline IM. Regarding the comments on 
the environmental impacts of pipe replacement, as discussed above, the 
impacts of replacing infrastructure that is operating beyond the design 
useful life are not attributable to the final rule requirements. While 
the final RIA assumes that operators will comply with MAOP 
reconfirmation using pipe replacement for approximately 300 miles of 
pipe, PHMSA did not consider these replacements to be incremental 
costs. Similarly, the environmental impacts are not attributable to the 
final rule requirements.
Other Impacts
    PHMSA disagrees with the analysis of operators shifting resources 
away from safety programs to comply with the proposed rule. PHMSA has 
revised and clarified the pipeline safety and integrity applicability 
of the final rule such that many operators will incur lower costs than 
previously anticipated. The final rule also provides long compliance 
schedules to enable planning for efficient compliance actions.

IV. GPAC Recommendations

    This section briefly summarizes the NPRM proposals, the GPAC's 
major comments on the proposals discussed, and the recommendations of 
the committee regarding how those provisions should be finalized. More 
detail, the presentations, and the transcripts from all of the meetings 
are available in the docket for this rulemaking.\83\ The provisions, 
which are presented in the order they were discussed at the GPAC 
meetings, the changes the committee agreed upon, and the corresponding 
vote counts are as follows:
---------------------------------------------------------------------------

    \83\ https://www.regulations.gov/docket?D=PHMSA-2011-0023.
---------------------------------------------------------------------------

6-Month Grace Period for 7-Calendar-Year Reassessment Intervals (Sec.  
192.939(b))
    In the NPRM, PHMSA proposed to allow operators to request a 6-month 
extension of the 7-calendar-year reassessment interval if the operator 
submits written notice to the Secretary with sufficient justification 
of the need for the extension in accordance with the technical 
correction at section 5 of the 2011 Pipeline Safety Act. The committee 
had no objections or substantial comments on this provision and voted 
12-0 that it was, as published, technically feasible, reasonable, cost-
effective, and practicable.
Safety Features on ILI Launchers and Receivers (Sec.  192.750)
    In the NPRM, PHMSA proposed to require operators equip ILI tool 
launchers and receivers with a device capable of safely relieving 
pressure in the barrel before the insertion or removal of ILI tools, 
scrapers, or spheres. Further, PHMSA proposed requiring operators to 
use a suitable device to indicate that pressure has been relieved in 
the barrel or otherwise provide a means to prevent the opening of the 
barrel if pressure has not been relieved. The committee voted 12-0 that 
this provision was, as published, technically feasible, reasonable, 
cost-effective, and practicable, as long as PHMSA clarified that the 
rule language does not require ``relief valves'' or use ``relief 
valve'' as a term. Some committee members were concerned that using 
language related to ``relief valves'' would bring in other code 
requirements, which was not PHMSA's intent.
Seismicity (Sec. Sec.  192.917, 192.935(b)(2))
    In the NPRM, PHMSA proposed to include seismicity in the list of 
factors operators must evaluate for the threat of outside force damage 
when considering preventative and mitigative measures, as well as 
include the seismicity of an area as a pipeline attribute in an 
operator's data gathering and integration when performing risk 
analyses. The committee had no substantial comments or recommendations 
on this topic, and

[[Page 52225]]

they voted 12-0 that this provision was, as published, technically 
feasible, reasonable, cost-effective, and practicable.
Records (Sec. Sec.  192.5(d), 192.13(e), 192.67, 192.127, 192.205, 
192.227(c), 192.285(e), 192.619(f), 192.624(f), Appendix A)
    In the NPRM, PHMSA proposed to clarify that the records required by 
part 192 must be documented in a reliable, traceable, verifiable, and 
complete manner. PHMSA summarized the recordkeeping requirements of 
part 192 in a new Appendix A, and required that operators must re-
establish pipeline documentation whenever records were not available 
and make and retain records demonstrating compliance with part 192. 
Issues related to records were discussed through the final 4 GPAC 
meetings over the course of 2017 and 2018. The committee found the 
assorted provisions related to records as being technically feasible, 
reasonable, cost-effective, and practicable, if certain changes were 
made. Specifically, the committee recommended the word ``reliable'' be 
deleted from the records standard so that it reads ``traceable, 
verifiable, and complete'' records wherever the standard is used. 
Members noted that the NTSB never used the term ``reliable,'' and a 
PHMSA advisory bulletin reflects the language without referring to 
``reliable'' records. In the class location requirements at Sec.  
192.5, the committee recommended PHMSA clarify that documentation be 
required to substantiate the current class location and not previous 
historical ones. The committee also recommended that PHMSA modify the 
requirements for the qualification of welders and persons joining 
plastic pipe to include an effective date and change the records 
retention provision to a period of 5 years.
    During the June 2017 GPAC meeting, the committee recommended PHMSA 
amend provisions related to the general duty clause for records and 
edit the corresponding reference to retention periods in Appendix A. 
After further discussion, during the meeting on March 2, 2018, the 
committee recommended PHMSA withdraw the proposed addition of Sec.  
192.13. Similarly, in the June 2017 meeting, the committee recommended 
PHMSA modify the proposed Appendix A to clarify that it does not apply 
to distribution or gathering pipelines. After considering the issue at 
the meeting on March 2, 2018, the committee recommended PHMSA withdraw 
proposed Appendix A from the rulemaking.
    Other changes the committee suggested regarding the proposed 
recordkeeping requirements included revising the record provisions for 
materials, pipe design, and components to clarify the effective date of 
those provisions and recommended PHMSA clarify that the recordkeeping 
provisions for components only applies to components greater than 2 
inches in nominal diameter. The recordkeeping provisions proposed under 
the MAOP determination and MAOP reconfirmation sections were discussed 
by the GPAC separately and are expanded upon under the discussions for 
those specific topics below.
    Following those discussions over the course of multiple meetings, 
the committee voted unanimously that the provisions related to 
recordkeeping requirements in part 192 were technically feasible, 
reasonable, cost-effective, and practicable, if PHMSA made the changes 
outlined above.
IM Clarifications (Sec. Sec.  192.917(e)(2), (e)(3) & (e)(4))
    In the NPRM, PHMSA proposed several changes to provisions related 
to how operators use data in their IM programs and manage certain types 
of defects. PHMSA proposed changes regarding an operator's analysis of 
cyclic fatigue and clarifying that certain pipe, such as low-frequency 
electric resistance welded pipe, must have been pressure tested for an 
operator to assume that any seam flaws are stable. PHMSA also proposed 
that any failures or changes to operation that could affect seam 
stability must be evaluated using a fracture mechanics analysis.
    Regarding cyclic fatigue, some GPAC members expressed concern that 
PHMSA proposed to require an annual analysis of cyclic fatigue even if 
the underpinning conditions affecting cyclic fatigue had not changed. 
Certain GPAC members wanted to ensure that it would be a change in 
conditions that would trigger an evaluation and that operators would 
not necessarily need to do an evaluation within a certain period 
otherwise. During the meeting, PHMSA suggested it would consider 
changing cyclic fatigue analysis from annually to periodically based on 
any changes to cyclic fatigue data and other changes to loading 
conditions since the previous analysis was completed, not to exceed 7 
calendar years. Further, PHMSA would consider whether there was 
conflict with this section and the MAOP reconfirmation requirements, 
which was a concern brought up during the public comment period of the 
meeting. Following the discussion, the committee voted 11-0, that the 
provisions related to cyclic fatigue were technically feasible, 
reasonable, cost-effective, and practicable if PHMSA revised the 
paragraph based on the GPAC member discussion and PHMSA's proposed 
language at the meeting.
    For the provisions related to the stability of manufacturing- and 
construction-related defects, PHMSA proposed during the GPAC meeting to 
provide that an operator could consider manufacturing- and 
construction-related defects as stable only if the covered segment has 
been subjected to a subpart J pressure test of at least 1.25 times MAOP 
and the covered segment has not experienced a reportable incident 
attributed to a manufacturing or construction defect since the date of 
the most recent subpart J pressure test. Pipeline segments that have 
experienced a reportable incident since its most recent subpart J 
pressure test due to an original manufacturing-related defect, a 
construction-related defect, an installation-related defect, or a 
fabrication-related defect would be required to be prioritized as a 
high-risk segment for the purposes of a baseline assessment or a 
reassessment. PHMSA proposed to explicitly lay out these requirements 
in the regulations rather than cross-reference these requirements to 
the MAOP reconfirmation provisions. Additionally, PHMSA indicated it 
would create a stand-alone section to deal with pipeline cracking 
issues within the IM regulations and would delete a specific reference 
to ``pipe body cracking'' in the provisions related to electric 
resistance welded pipe.
    Following the discussion, the committee voted 12-0 that the 
provisions related to IM clarifications regarding manufacturing and 
construction defects were technically feasible, reasonable, cost-
effective, and practicable if PHMSA made the changes it proposed during 
the meeting, created a new, stand-alone section for addressing pipeline 
cracking within the IM regulations, deleted the phrase related to 
``pipe body cracking,'' and considered allowing other test procedures 
for determining whether manufacturing- and construction-related defects 
were stable.
MAOP Exceedances (Sec. Sec.  191.23, 191.25)
    In the NPRM, PHMSA proposed requiring operators to report each 
exceedance of the MAOP that exceeds the build-up allowed for the 
operation of pressure-limiting or control devices per the congressional 
mandate provided in the 2011 Pipeline Safety Act, which requires 
operators to report such exceedances on or before the 5th day

[[Page 52226]]

following the date on which the exceedance occurs.
    During the public comment period of the June 7, 2017, meeting, a 
commenter expressed concern that being required to report an exceedance 
within 5 days might be problematic where an ongoing investigation might 
preclude an operator from being able to complete a full safety-related 
condition report. The GPAC considered this viewpoint but noted that the 
5-day reporting requirement was prescribed by statute, and PHMSA does 
not have discretion when implementing that deadline. The GPAC, echoing 
another comment from the public, discussed whether the provision would 
be applicable to gathering lines. PHMSA, in response, noted that the 
requirement would be limited to gas transmission lines only. Following 
the discussion, the GPAC voted 11-0 that the provision was technically 
feasible, reasonable, cost-effective, and practicable if PHMSA 
clarified that this provision does not apply to gathering lines.
Verification of Pipeline Material Properties and Attributes (Sec.  
192.607)
    In the NPRM, PHMSA proposed a process for operators to re-establish 
material properties on pipelines where those attributes may be unknown. 
The process was an opportunistic sampling approach that did not require 
any mandatory excavations and allowed operators to verify material 
properties of pipelines as opportunities presented themselves during 
normal operations and maintenance, such as excavations for the repair 
of anomalies.
    The GPAC had a robust discussion on the proposed material 
properties verification requirements and wanted to clarify that two 
separate activities--MAOP reconfirmation and the application of IM 
principles--drive the need for material properties verification and 
should be addressed separately. Overall, the GPAC was supportive of 
PHMSA's opportunistic approach for verifying material properties. 
During the public comment period, members representing the pipeline 
industry suggested PHMSA allow a statistical sampling plan developed by 
operators instead of prescribing a specific number of samples needed. 
PHMSA clarified that it expected a 1 pipe-per-mile sampling standard in 
most cases.
    At the December 2017 GPAC meeting, some GPAC members expressed 
concern with the specific attributes PHMSA was proposing operators 
collect and verify. There was also some discussion regarding how the 
notification procedure PHMSA proposed might be cumbersome if operators 
would be required to wait on a response or action from PHMSA every time 
an operator wanted to submit an alternative plan. The GPAC suggested 
adding language where, if PHMSA was to object to an operator 
notification, they would have to object within 90 days. If PHMSA did 
not object within 90 days, the operator would be free to go forward 
with the intended action.
    Following the discussion, the GPAC voted 12-0 that the provisions 
related to material properties verification were technically feasible, 
reasonable, cost-effective, and practicable if the following changes 
were made:
     Clarify that material properties verification applies to 
onshore steel transmission lines only, and not distribution or 
gathering lines.
     Remove the applicability criteria of the section and make 
the material properties verification provisions a procedure that 
operators can use for obtaining missing or inadequate records or 
verifying pipeline attributes if required by the MAOP reconfirmation 
provisions or other code sections. The committee agreed to address the 
applicability of the material properties verification requirements 
under each of the MAOP reconfirmation methods and other sections as 
appropriate.
     Delete the requirements for creating a material properties 
verification program plan.
     Drop the list of mandatory attributes operators would be 
required to verify but require that operators keep any records 
developed through this material properties verification method.
     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 use their own statistical approach and 
submit a notification to PHMSA with their method. Establish a minimum 
standard of a 95% confidence level for operator statistical methods 
submitted to PHMSA.
     Retain flexibility to allow either destructive or non-
destructive tests when verification is needed.
     Incorporate language stating that, if an operator does not 
receive an objection letter from PHMSA within 90 days of notifying 
PHMSA of an alternative sampling approach, the operator can proceed 
with their method. PHMSA will notify the operator if additional review 
time is needed.
     Revise the paragraph to accommodate situations where a 
single material properties verification test is needed (e.g., 
additional information is needed for an anomaly evaluation/repair).
     Drop accuracy specifications (retain requirement that test 
methods must be validated and that calibrated equipment be used).
     Drop mandatory requirements for multiple test locations 
for large excavations (multiple joints within the same excavation).
     Reduce number of quadrants at which NDE tests must be made 
from 4 to 2.
     Delete specified program requirements for how to address 
sampling failures and replace 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. Require 
notification to provide expanded sample program to PHMSA, and require 
operators establish a minimum standard that sampling programs must be 
based on a minimum 95% confidence level.
     Clarify the applicability of Sec.  192.607 (d)(3)(i).
Strengthened Assessment Requirements (Appendix F, Sec. Sec.  192.493, 
192.506, 192.921(a))
    In the NPRM, PHMSA proposed to clarify the selection and conduct of 
ILI tools per updated industry standards that would be incorporated by 
reference, clarify the consideration of uncertainties in ILI reported 
results, add additional assessment methods to allow greater flexibility 
to operators, and allow direct assessment as a method only if the 
pipeline was not piggable. PHMSA also proposed to explicitly allow 
guided wave ultrasonic testing (GWUT) in the list of integrity 
assessment methods by codifying in a new Appendix F the current 
guidelines operators use for submitting GWUT inspection procedures.
    For the updated ILI standards, some GPAC members requested PHMSA 
delete the ``requirements and recommendations'' language in Sec.  
192.493 and other places where standards are incorporated by reference 
to avoid the consequence that non-mandatory recommendations in the 
standards would become regulatory requirements. Following the 
discussion, the GPAC voted 10-0 that the provisions related to 
strengthened assessment requirements pertaining to in-line assessment 
standards were technically feasible, reasonable, cost-effective, and 
practicable if PHMSA struck the phrase ``the requirements and 
recommendations of'' from the appropriate paragraph in Sec.  192.493.

[[Page 52227]]

    Regarding the usage of assessment methods, certain committee 
members recommended PHMSA allow the direct assessment method whenever 
appropriate (i.e., do not restrict the use of direct assessments to 
unpiggable pipeline segments or when other methods are impractical) and 
incorporate better language to clarify when it is appropriate for 
operators to use direct assessments. Similarly, the GPAC suggested 
PHMSA clarify the regulatory language so that it was clear operators 
must select the appropriate assessment method based on the applicable 
threats. The clarification would avoid the implication that operators 
need to run certain tools against certain threats when there is no 
evidence or susceptibility of that threat for that particular pipeline 
segment.
    The GPAC also recommended that PHMSA delete the proposed 
requirement in the baseline assessment method that required a review of 
ILI results by knowledgeable individuals, since it is duplicative with 
other existing requirements elsewhere in the regulations. Further, some 
GPAC members expressed concern that all tools cannot meet the 90 
percent tool tolerance that is specified in the referenced industry 
standard. PHMSA representatives noted that the rule would not require 
that every tool perform within a 90 percent specification rate, but 
that actual tool performance should be verified and applied when ILI 
data is interpreted. As in other sections of the proposed regulations, 
the committee also requested PHMSA adopt the same objection procedure 
that the GPAC discussed and approved under the material properties 
verification provisions for any notification under this section.
    Following the discussion, the GPAC voted 10-0 that the provisions 
related to strengthening the conduct of a baseline integrity assessment 
were technically feasible, reasonable, cost-effective, and practicable 
if PHMSA revised the requirements to clarify that operators must select 
assessment methods based on the threats to which the pipeline is 
susceptible and removed language in the provision that is duplicative 
with requirements elsewhere in the regulations; clarified that direct 
assessment is allowed where appropriate but may not be used to assess 
threats for which the method is not suitable; and incorporated the same 
objection procedure the committee approved for the material properties 
verification provisions and with a PHMSA review timeframe of 90 days.
    In discussing the provisions related to the ``spike'' hydrostatic 
pressure test method, the committee had several comments and 
recommendations. Specifically, some GPAC members recommended that the 
spike test should be performed at a pressure level of 100 percent SMYS, 
and not 105 percent, to account for varying elevations and test segment 
lengths. They also suggested that the 30-minute hold time was too long 
and requested PHMSA consider minimizing the duration of the spike 
pressure to avoid growing subcritical cracks. Further, the GPAC 
recommended PHMSA clarify that spike testing should be performed 
against the threat of ``time-dependent cracking'' and remove instances 
in other sections of the regulations where PHMSA listed the threats for 
which a spike pressure test is appropriate. Following the discussion, 
the committee voted 10-0 that the provisions related to the ``spike'' 
hydrostatic pressure test method were technically feasible, reasonable, 
cost-effective, and practicable if PHMSA changed the minimum spike 
pressure to whichever is lesser: 100 percent SMYS or 1.5 times MAOP, 
reduced the spike hold time to a minimum of 15 minutes after the spike 
pressure stabilizes, referred to ``time-dependent cracking'' in the 
section, incorporated the same objection procedure the committee 
approved for the material properties verification provisions and with a 
PHMSA review timeframe of 90 days, and incorporated the term 
``qualified technical subject matter expert'' (SME) at the SME 
requirements.
    The GPAC did not have major concerns with incorporating the GWUT 
procedures into the regulations and voted 13-0 that the provisions 
related to the GWUT process were technically feasible, reasonable, 
cost-effective, and practicable if PHMSA revised the objection 
procedure as recommended by GPAC members during the discussion on the 
proposed material properties verification requirements and considering 
certain minor technical recommendations made by the GPAC members.
Moderate Consequence Area Definition (Sec.  192.3)
    In the NPRM, PHMSA proposed a new definition for ``Moderate 
Consequence Areas'' (MCA) which would be areas operators would have to 
assess per the proposed requirements for performing integrity 
assessments outside of HCAs. PHMSA proposed to define an MCA as an area 
in a ``potential impact circle'' \84\ with 5 or more buildings intended 
for human occupancy; an ``occupied site;'' or the right-of-way of an 
interstate, freeway, expressway, and other principal 4-lane arterial 
roadway. PHMSA proposed the definition of an ``occupied site'' to be 
areas or buildings occupied by 5 or more persons, which was the same as 
an ``identified site'' under the HCA definitions at Sec.  192.903, 
except that the occupancy threshold was lowered from 20 persons to 5 
persons.
---------------------------------------------------------------------------

    \84\ A ``potential impact circle'' is defined under Sec.  
192.903 as ``a circle of radius equal to the potential impact 
radius,'' where the ``potential impact radius'' is the radius of a 
circle within which the potential failure of a pipeline could have 
significant impact on people or property.
---------------------------------------------------------------------------

    The GPAC, based on a comment made by a member of the public, asked 
if PHMSA could provide more guidance on what a ``piggable'' line is, 
for the purposes of this definition. The GPAC asked whether PHMSA 
believed that qualifier applies to pipelines that can be fully assessed 
by a traditional, free-swimming ILI tool without further modification 
to the pipeline, and PHMSA noted during the meeting that a ``piggable'' 
line would be one without physical or operational modifications. The 
GPAC then suggested PHMSA clarify that definition in the preamble of 
this final rule.
    GPAC members representing the public were concerned about PHMSA's 
proposal during the meeting to eliminate the concept of an ``occupied 
site'' from the MCA definition. Industry members argued that, from a 
practicability standpoint, determining whether five people were in a 
location at any given time could be difficult, and there was 
significant overlap between ``occupied sites'' and the class locations 
that would need to be assessed per the proposal. The GPAC discussed 
whether some of these sites would be included within an operator's HCA 
identification program already and, if not, whether operators would be 
able to otherwise incorporate ``occupied sites'' into their 
identification and assessment programs.
    Several GPAC members discussed whether PHMSA should create a 
database or provide other guidance on which highways should be included 
in the MCA definition for consistency between PHMSA, State regulators, 
and operators. Those comments regarding highways were made following a 
public comment asking whether certain elevated highways needed to be 
included.
    Following the discussion, the GPAC voted 10-0 that the MCA 
definition was technically feasible, reasonable, cost-effective, and 
practicable if PHMSA

[[Page 52228]]

changed the highway description to remove the reference to ``rights-of-
way'' and added language so that the highway description includes ``any 
portion of the paved surface, including shoulders;'' clarified that 
highways with 4 or more lanes are included within the definition; 
discussed in the preamble what the definition of ``piggable'' is; and 
worked with the Federal Highway Administration to provide operators 
with clear information and discuss it in the preamble of this final 
rule. Additionally, the GPAC recommended PHMSA modify the term 
``occupied sites'' in the definition by removing ``5 or more persons'' 
and the occupancy timeframe of 50 days, and tie the requirement into 
the HCA survey for ``identified sites'' as discussed by members and 
PHMSA at the meeting. Such identification could be made through 
publicly available databases and class location surveys, and PHMSA was 
to consider the sites and enforceability per direction by the committee 
members.
Assessments Outside of HCAs (Sec.  192.710)
    In the NPRM, PHMSA proposed to require operators perform integrity 
assessments of certain pipelines outside of HCAs. Specifically, 
operators would perform an initial assessment within 15 years and 
periodic assessments 20 years thereafter of pipelines in Class 3 and 
Class 4 locations as well as piggable pipelines in newly-defined 
``moderate consequence areas'' as discussed above.
    The GPAC, based on a public comment during the meeting, questioned 
whether the timeframes for the initial assessment and periodic 
assessments were appropriate. Members debated shortening the time 
frames and suggested a few timeframes that could be based on a risk-
based prioritization and taking into account timeframes for HCA 
assessments.
    Following the discussion, the GPAC voted 10-0 that the provisions 
related to assessments outside of HCAs were technically feasible, 
reasonable, cost-effective, and practicable if PHMSA clarified that 
direct assessment can be used as an assessment method only if 
appropriate for the threat being assessed but cannot be used to assess 
threats for which direct assessment is not suitable; revised the 
initial assessment and reassessment intervals from 15 years and 20 
years, respectively, to 14 years and 10 years, respectively, and with a 
risk-based prioritization; revised the applicability requirements to 
apply to lines with MAOPs of 30 percent SMYS or greater; and removed 
the provisions related to low-stress assessments.
MAOP Reconfirmation (Sec.  192.624)
    In the NPRM, PHMSA proposed a testing regime for (1) pipelines in 
HCAs, Class 3 or Class 4 locations, or ``piggable'' MCAs that 
experienced a reportable in-service incident due to certain types of 
defects since its most recent successful subpart J pressure test, (2) 
pipelines in HCAs or Class 3 or Class 4 locations that lacked the 
traceable, verifiable, and complete pressure test records necessary to 
substantiate the current MAOP, and (3) pipelines in HCAs, Class 3 or 
Class 4 locations, or piggable MCAs where the operator established the 
MAOP using the ``grandfather'' clause pursuant to Sec.  192.619(c). 
PHMSA proposed operators of these pipelines re-confirm the MAOP of 
those pipelines by choosing and executing one of a variety of methods. 
Those methods are discussed in more detail in individual sections 
below.

MAOP Reconfirmation Scope and Completion Date

    During the discussion on MAOP reconfirmation, some GPAC members 
suggested PHMSA revise the applicability of the provisions to remove 
pipeline segments with prior crack or seam incidents, as those issues 
would be dealt with in an operator's IM program. Certain committee 
members recommended PHMSA restrict the scope of the MAOP reconfirmation 
provisions to pipeline segments with MAOPs of 30 percent SMYS or 
greater. These members argued that threshold was explicit in the 
congressional mandate as it pertained to previously untested pipe, and 
that it was based on the concept that lower-stress lines leak rather 
than rupture. Members further suggested that the benefit in addressing 
low-stress lines was not commensurate with the cost of doing so. Other 
committee members supported retaining the scope of PHMSA's proposals in 
the NPRM in order to address specific NTSB recommendations.
    Following the discussion, the committee voted 13-0 that the 
provisions related to the scope for MAOP reconfirmation were 
technically feasible, reasonable, cost-effective, and practicable if 
PHMSA removed pipelines with previous reportable incidents due to crack 
defects from the applicability paragraph; addressed pipeline segments 
with crack incident history in a new paragraph under the IM 
requirements; withdrew the definitions for ``modern pipe,'' ``legacy 
pipe,'' and ``legacy construction techniques;'' revised a reference to 
necessary records within the applicability paragraph to refer to 
records needed for MAOP determination and not subpart J pressure test 
records; and revised the applicability of the requirements for 
grandfathered lines to apply only to those lines with MAOPs of 30 
percent or greater of SMYS. The committee also recommended PHMSA review 
the costs and benefits of making the requirements applicable to Class 3 
and Class 4 non-HCA pipe operating below 30 percent SMYS.
    As for the completion date for the MAOP reconfirmation 
requirements, the GPAC voted 13-0 that the related provisions were 
technically feasible, reasonable, cost-effective, and practicable if 
PHMSA addressed how the completion plan and completion dates required 
by the section would apply to pipelines that currently do not meet the 
applicability conditions but may in the future. The committee suggested 
PHMSA could add a phrase stating that operators must complete all 
actions required by the section on 100 percent of the applicable 
pipeline mileage 15 years after the effective date of the rule or, as 
soon as practicable but not to exceed 4 years after the pipeline 
segment first meets the applicability conditions, whichever date is 
later. The GPAC also recommended that PHMSA consider a waiver or no-
objection procedure for extending that timeline past 4 years, if 
necessary.

MAOP Reconfirmation: Methods 1 and 2 (Pressure Test and Pressure 
Reduction)

    In the NPRM, PHMSA proposed six methods an operator could use if 
needing to reconfirm MAOP. Method 1, a hydrostatic pressure test, would 
be conducted at 1.25 times MAOP or the MAOP times the class location 
test factor, whichever is greater. PHMSA proposed operators use a 
``spike'' test method on pipeline segments with reportable in-service 
incidents due to known manufacturing or construction issues, and PHMSA 
also proposed operators estimate the remaining life of pipeline 
segments with crack defects. Method 2, a pressure reduction, would 
allow operators to reduce the pipeline segment's MAOP to the highest 
operating pressure divided by 1.25 times MAOP or the class location 
test factor times MAOP, whichever is greater. Similar to Method 1, 
PHMSA proposed operators taking a pressure reduction to reconfirm MAOP 
be required to estimate the remaining life of pipeline segments with 
crack defects.
    The GPAC members representing the industry argued that a ``spike'' 
test is more appropriate to include under IM requirements and that it 
is not

[[Page 52229]]

appropriate for MAOP reconfirmation. During the meeting, PHMSA noted 
that if the scope of the MAOP reconfirmation provisions was to be 
revised to delete lines with crack-like defects, the spike test 
requirement would not be needed. However, PHMSA would expect the spike 
test provisions to be utilized when otherwise required by the 
regulations. GPAC members also suggested adding language to address 
material properties verification requirements with respect to the 
information that is needed to conduct a pressure test. At the meeting, 
PHMSA suggested that the GPAC consider explicitly requiring that any 
information an operator does not have to perform a successful pressure 
test in accordance with subpart J (or that is not documented in 
traceable, verifiable, and complete records) be verified in accordance 
with the material properties verification provisions.
    Following the discussion, the GPAC voted 12-0 that the provisions 
related to the pressure test method for MAOP reconfirmation were 
technically feasible, reasonable, cost-effective, and practicable if 
PHMSA deleted the spike hydrostatic testing component for pipelines 
with suspected crack defects and referred to subpart J more broadly 
instead of certain sections within subpart J. The GPAC also recommended 
that if the pressure test segment does not have traceable, verifiable, 
and complete MAOP records, operators should use the best available 
information upon which the MAOP is currently based to perform the 
pressure test. The committee recommended PHMSA require operators of 
such pipeline segments add those segments to its plan for 
opportunistically verifying material properties in accordance with the 
material properties verification requirements, noting that most 
pressure tests will present at least two opportunities for material 
properties verification at the test manifolds.
    As for the pressure reduction method of MAOP reconfirmation, the 
GPAC voted 12-0 that the related provisions were technically feasible, 
reasonable, cost-effective, and practicable if PHMSA increased the 
look-back period from 18 months to 5 years and removed the requirement 
for operators to perform fracture mechanics analysis on those pipeline 
segments where the pressure is being reduced to reconfirm the MAOP.

MAOP Reconfirmation: Method 3 (Engineering Critical Assessment and 
Fracture Mechanics)

    In the NPRM, PHMSA proposed allowing operators to use an 
engineering critical assessment (ECA) analysis in conjunction with an 
ILI assessment to reconfirm a pipeline segment's MAOP where the 
segment's MAOP would be based upon the lowest predicted failure 
pressure (PFP) of the segment. This method would require specific 
technical documentation and material properties verification, and it 
would require operators analyze crack, metal loss, and interacting 
defects remaining in the pipe, or that could remain in the pipe, to 
determine the PFP. The pipeline segment's MAOP would then be 
established at the lowest PFP divided by 1.25 or by the applicable 
class location factor listed under the MAOP determination provisions, 
whichever of those derating factors is greater.
    Most of the GPAC discussion on this portion of MAOP reconfirmation 
related to the specific values used in the fracture mechanics analysis 
portion of the ECA and whether those requirements would best be located 
in a section independent from the MAOP reconfirmation requirements. 
During the meetings, PHMSA noted it would consider creating a stand-
alone fracture mechanics section that could be referenced when the 
procedure is needed or required by other sections of the regulations. 
PHMSA clarified that fracture mechanics would be needed in the context 
of MAOP reconfirmation only for the ECA method and ``other technology'' 
usage under Method 6 where the applicable pipeline segments have cracks 
or crack-like defects.
    Following the discussion, the GPAC voted 12-0 that the provisions 
related to the ECA method of MAOP reconfirmation and fracture mechanics 
were technically feasible, reasonable, cost-effective, and practicable 
if PHMSA moved the fracture mechanics requirements to a stand-alone 
section in the regulations. The GPAC recommended the section not 
specify when, or for which pipeline segments, fracture mechanics 
analysis would be required, but instead provide a procedure by which 
operators needing to perform fracture mechanics analysis could do so.
    The GPAC recommended several changes to the fracture mechanics 
requirements, including striking cross-references to the MAOP 
reconfirmation requirements and spike hydrostatic testing requirements, 
as well as striking the sensitivity analysis requirements and replacing 
them with a requirement that operators account for model inaccuracies 
and tolerances. Additionally, the GPAC recommended PHMSA add a 
paragraph specifying that any records created through the performance 
of a fracture mechanics analysis must be retained.
    There were several technical GPAC recommendations related to the 
use of Charpy V-notch toughness values in the fracture mechanics 
analysis. Specifically, the GPAC recommended operators have the ability 
to use a conservative Charpy V-notch toughness value based on the 
sampling requirements of the material properties verification 
provisions, and that operators could use Charpy V-notch toughness 
values from similar or the same vintage pipe until the properties are 
obtained through an opportunistic testing program. Further, the GPAC 
recommended that the default Charpy V-notch toughness values (full-size 
specimen, based on the lowest operational temperature) of 13-ft.-lbs. 
(body) and 4-ft.-lbs. (seam) only apply to pipe with suspected low-
toughness properties or unknown toughness properties. Additionally, the 
GPAC recommended PHMSA include a requirement for operators of pipeline 
segments with a history of leaks or failures due to cracks to work 
diligently to obtain toughness data if unknown and use Charpy V-notch 
toughness values (full-size specimen, based on the lowest operational 
temperature) of 5-ft.-lbs. (body) and 1-ft.-lbs. (seam) in the interim. 
Further, the GPAC suggested PHMSA allow operators to request the use of 
different default Charpy V-notch toughness values via a 90-day 
notification to PHMSA.
    For the ECA method itself, the committee recommended PHMSA add a 
requirement to verify material properties in accordance with the 
material properties verification requirements if the information needed 
to conduct an ECA is not documented in traceable, verifiable, and 
complete records. Further, the GPAC recommended that PHMSA not include 
default Charpy V-notch toughness values or other technical fracture 
mechanics requirements in the ECA method, as those items would be 
specified in the new stand-alone fracture mechanics section. Similarly, 
the GPAC recommended removing ILI tool performance specifications and 
replacing them with a requirement to verify tool performance using 
unity plots or equivalent technologies.

MAOP Reconfirmation: Methods 4, 5, and 6 (Pipe Replacement, Small-
Diameter & Potential Impact Radius Pressure Reduction, and Other 
Technology)

    In the NPRM, PHMSA proposed three additional methods operators 
could use to reconfirm a pipeline's MAOP. Method 4, pipe replacement, 
would require operators to replace pipe for

[[Page 52230]]

which they have inadequate records or pipe that was not previously 
tested due to the grandfather clause in Sec.  192.619(c). Method 5, as 
proposed, was applicable to low-stress, small diameter, and small 
potential impact radius (PIR) lines,\85\ and would require operators to 
take a 10 percent pressure cut as well as perform more frequent patrols 
and leak surveys. Method 6, ``other technology,'' would allow operators 
to use an alternative method, with notification to PHMSA, to reconfirm 
the MAOP of their applicable pipeline segments.
---------------------------------------------------------------------------

    \85\ These lines would be lines operating below 30 percent SMYS 
with diameters of 8 inches or less and PIRs of 150 feet or less.
---------------------------------------------------------------------------

    The GPAC had no major comments regarding Method 4, pipe 
replacement. For Method 5, GPAC members representing the industry 
questioned the need for the compensatory safety measures, such as the 
additional patrols and leak surveys, in conjunction with the 10 percent 
pressure reduction. They also supported public comments that promoted 
expanding the applicability of Method 5 beyond the prescribed pipe 
diameter of less than or equal to 8 inches and the operating pressure 
of below 30 percent SMYS. During the meeting, PHMSA noted it could drop 
the diameter and operating pressure requirements from the applicability 
and use the prescribed PIR of 150 feet or less as a proxy for those 
risk factors. Additionally, PHMSA noted it would expand the look-back 
period to 5 years to be consistent with committee and public comments 
regarding the pressure reduction method (Method 2) of MAOP 
reconfirmation discussed earlier. With regard to the ``other 
technology'' method, committee members suggested using the notification 
procedure developed for the material properties verification 
requirements, and PHMSA acknowledged it could be included here as well.
    Following the discussion, the committee voted 11-0 that the 
provisions related to the pipe replacement, pressure reduction for 
small PIR and diameter lines, and ``other technology'' methods of MAOP 
reconfirmation were technically feasible, reasonable, cost-effective, 
and practicable if PHMSA made certain changes. For Method 4, pipe 
replacement, the committee had no significant comments or changes. For 
Method 5, the small PIR and diameter pressure reduction method, the 
GPAC recommended PHMSA delete the size and pressure criteria, limiting 
the requirement to those lines with a PIR of 150 feet or less; remove 
the external corrosion direct assessment, crack analysis program, 
odorization, and fracture mechanics analysis requirements; and change 
the frequency of patrols and surveys to 4 times per year in Class 1 and 
Class 2 locations and 6 times per year in Class 3 and Class 4 
locations. For Method 6, the ``other technology'' method, the GPAC 
recommended PHMSA incorporate the same 90-day notification and 
objection procedure the GPAC approved for the material properties 
verification requirements.

MAOP Reconfirmation: Recordkeeping and Notification

    The GPAC also voted on the notification procedure and recordkeeping 
requirements of the MAOP reconfirmation requirements. As there were no 
substantial GPAC comments on these issues, the GPAC voted 11-0 that the 
provisions are technically feasible, reasonable, cost-effective, and 
practicable if PHMSA provided guidance regarding what ``traceable, 
verifiable, and complete'' records are in the preamble, and if the 
notification procedure is retained as it was proposed in the NPRM, but 
incorporating the same 90-day notification and objection procedure the 
committee approved for the material properties verification 
requirements into any notification required under the MAOP 
reconfirmation requirements.
Other MAOP Amendments (Sec. Sec.  192.503, 192.605(b)(5), 
192.619(a)(2), 192.619(a)(4), 192.619(e), 192.619(f))
    PHMSA presented to the committee issues related to other portions 
of MAOP determination \86\ that had cross-references to MAOP 
reconfirmation methods or other areas of the proposed regulations. More 
specifically, the GPAC was to consider recommending PHMSA eliminate 
duplications in scope between the MAOP determination provisions and the 
MAOP reconfirmation provisions, and eliminate a duplicative revision to 
the subpart J pressure test general requirements that was referenced 
adequately elsewhere in the proposal. PHMSA also proposed that the 
establishment of MAOP under Sec.  192.619 should rely on traceable, 
verifiable, and complete records, and therefore cross-referenced the 
material properties verification provisions with the MAOP determination 
provisions. Similarly, PHMSA added a paragraph to the existing MAOP 
determination provisions to more clearly specify that operators must 
have records to substantiate the MAOP of their pipeline segments. To 
address an NTSB recommendation from the PG&E incident, PHMSA also 
proposed requiring that the MAOP pressure limitation factor specified 
in the MAOP determination section of the regulations for Class 1 
pipeline segments be based on the subpart J test pressure divided by 
1.25, whereas the existing requirement was the test pressure divided by 
1.1. Finally, PHMSA proposed adding a clarification that the 
requirement for overpressure protection applied to pipeline segments 
where the MAOP was established using one of the six methods under MAOP 
reconfirmation. However, PHMSA noted in response to public comment that 
the clarification seemed to be overly confusing and should be 
withdrawn.
---------------------------------------------------------------------------

    \86\ See Sec.  192.619.
---------------------------------------------------------------------------

    The GPAC reviewed and discussed PHMSA's proposed changes to the 
other MAOP-related provisions, voting 12-0 that the provisions are 
technically feasible, reasonable, cost-effective, and practicable if 
PHMSA considered editorially restructuring the applicability of the 
MAOP determination provisions; clarifying that the recordkeeping 
requirements specified under MAOP determination only apply to onshore, 
steel, gas transmission pipelines; and clarifying that the MAOP 
recordkeeping requirements are not retroactive. The GPAC suggested this 
be clarified by stating existing records for pipelines installed on or 
before the effective date of the rule must be kept for the life of the 
pipeline, that pipelines installed after the effective date of the rule 
must make and retain records as required for the life of the pipeline, 
and that MAOP records are required for any pipeline placed in service 
after the effective date of the rule. The GPAC noted that other 
sections, including the MAOP reconfirmation and material properties 
verification requirements, would require when and for which pipeline 
segments where MAOP records are not documented in a traceable, 
verifiable, and complete manner would need to be verified.
Changes From the GPAC Recommendations
    In this final rule, PHMSA considered the recommendations of the 
GPAC and adopted them as PHMSA deemed appropriate. However, there were 
recommendations from the GPAC that PHMSA considered but did not adopt. 
To summarize, the major changes PHMSA made in this rule that deviate 
from the GPAC recommendations are as follows:
    (1) When discussing the other proposed issues related to the MAOP 
requirements, the GPAC recommended

[[Page 52231]]

PHMSA consider moving Sec.  192.619(e) to be a subsection of Sec.  
192.619(a) and consider referencing section Sec.  192.624 in Sec.  
192.619(a). PHMSA did not implement this recommendation because MAOP 
reconfirmation for grandfathered segments is not applicable for new 
pipeline segments.
    (2) When considering the IM clarifications at Sec.  192.917, the 
GPAC recommended PHMSA consider removing the term ``hydrostatic'' from 
the testing requirements at Sec.  192.917(e)(3), which deals with 
manufacturing and construction defects, and allow other authorized 
testing procedures. PHMSA is not implementing this recommendation 
because allowing pneumatic tests would be a safety concern to the 
public and operating personnel.
    (3) When discussing the assessment requirements for non-HCAs under 
proposed Sec.  192.710, the GPAC recommended PHMSA change the 
``discovery of condition'' period allotted from 180 to 240 days. PHMSA 
is not implementing this suggestion from the GPAC and is retaining the 
180-day timeframe for operators to determine whether a condition 
presents a potential threat to the integrity of the pipeline.
    (4) PHMSA added a notification requirement for the use of other 
technology under the non-HCA assessment requirements at Sec.  192.710. 
While the GPAC did not specifically request PHMSA make this change, the 
GPAC was generally supportive of incorporating the notification 
procedure the committee agreed to under the proposed material 
properties verification requirements for other applications.
    (5) Regarding the requirements for the scope of MAOP 
reconfirmation, the GPAC recommended PHMSA review the costs and 
benefits of including Class 3 and Class 4 pipelines not located in HCAs 
and that operate at less than 30 percent SMYS. PHMSA did consider this 
as an alternative in the RIA but chose not to move forward with the 
proposal as suggested as it is outside the scope of the mandate.
    (6) Regarding the MCA definition, the GPAC recommended PHMSA 
consider modifying the term ``occupied sites'' within the definition by 
removing reference to ``5 or more persons'' and the timeframe of 50 
days and tying the requirement for identifying occupied sites to the 
HCA ``identified sites'' survey requirement as discussed by members and 
PHMSA at the meeting. In this final rule, PHMSA chose to delete the 
term ``occupied sites'' from the MCA definition and from the general 
definitions section of part 192.
    (7) PHMSA moved the specific ECA requirements outside of the MAOP 
reconfirmation section into a new stand-alone Sec.  192.632. The MAOP 
reconfirmation requirements regarding the ECA method at Sec.  
192.624(c)(3) and the ECA requirements in Sec.  192.632 will cross-
reference each other. PHMSA made this change to streamline the MAOP 
reconfirmation provisions and improve the readability of the 
requirements. No substantive changes were made to the procedure in 
connection with this reorganization; this was a stylistic change only.

V. Section-by-Section Analysis

Sec.  191.23 Reporting Safety-Related Conditions

    Section 23 of the 2011 Pipeline Safety Act requires operators to 
report each exceedance of MAOP that exceeds the margin (build-up) 
allowed for operation of pressure-limiting or control devices. On 
December 21, 2012, PHMSA published advisory bulletin ADB-2012-11, which 
advised operators of their responsibility under section 23 of the 2011 
Pipeline Safety Act to report such exceedances. PHMSA is revising Sec.  
191.23 to codify this statutory requirement.

Sec.  191.25 Filing Safety-Related Condition Reports

    Section 23 of the 2011 Pipeline Safety Act requires operators to 
report each exceedance of the MAOP that exceeds the margin (build-up) 
allowed for operation of pressure-limiting or control devices. As 
described above, PHMSA is revising Sec.  191.23 to codify this 
requirement. Section 191.25 is also revised to make conforming edits 
and comply with the mandatory 5-day reporting deadline specified in 
section 23 of the 2011 Pipeline Safety Act.

Sec.  192.3 Definitions

    Section 192.3 provides definitions for various terms used 
throughout part 192. In support of other regulations adopted in this 
final rule, PHMSA is amending the proposed definition of ``Moderate 
consequence area.'' This change will define this term as it is used 
throughout part 192.
    The definition of a ``moderate consequence area,'' or MCA, is based 
on similar methodology used to define ``high consequence area,'' or HCA 
in Sec.  192.903. Moderate consequence areas will define the subset of 
non-HCA locations where integrity assessments are required (Sec.  
192.710) and where MAOP reconfirmation is required (Sec.  192.624). The 
criteria for determining MCA locations differs from the criteria 
currently used to identify HCAs in that the threshold for buildings 
intended for human occupancy located within the potential impact radius 
is lowered from 20 to 5, and identified sites are excluded. In response 
to NTSB recommendation P-14-01, which was issued as a result of the 
incident near Sissonville, WV, the MCA definition also includes 
locations where interstate highways, freeways, expressways, and other 
principal 4-or-more-lane arterial roadways are located within the 
potential impact radius.
    PHMSA is also adopting a definition of an ``engineering critical 
assessment,'' as that term will be used in Sec. Sec.  192.624 and 
192.632. More specifically, the ECA is a documented analytical 
procedure that operators can use to determine the maximum tolerable 
size for pipeline imperfections based on the MAOP of the particular 
pipeline segment. Operators can use an ECA in conjunction with an ILI 
inspection as one of the methods to reconfirm MAOP, if required.

Sec.  192.5 Class Locations

    Section 23 of the 2011 Pipeline Safety Act requires the Secretary 
of Transportation to require verification of records used to establish 
MAOP to ensure they accurately reflect the physical and operational 
characteristics of certain pipelines and to confirm the established 
MAOP of the pipelines. PHMSA has determined that an important aspect of 
compliance with this requirement is to assure that pipeline class 
location records are complete and accurate. This final rule adds a new 
paragraph, Sec.  192.5(d), to require each operator of transmission 
pipelines to maintain records documenting the current class location of 
each pipeline segment and demonstrating how an operator determined each 
current class location in accordance with this section.

Sec.  192.7 What documents are incorporated by reference partly or 
wholly in this part?

    Section 192.7 lists documents that are incorporated by reference in 
part 192. PHMSA is making conforming amendments to Sec.  192.7 in the 
rule text to reflect other changes adopted in this final rule.

Sec.  192.9 What requirements apply to gathering lines?

    This final rule codifies new standards for gas transmission 
pipelines, most of which are not intended to be applied to gas 
gathering pipelines. PHMSA is making conforming amendments to Sec.  
192.9 to clarify which provisions

[[Page 52232]]

apply only to gas transmission pipelines and not to gas gathering 
pipelines.

Sec.  192.18 How To Notify PHMSA

    This final rule allows operators to notify PHMSA of proposed 
alternative approaches to achieving the objective of the minimum safety 
standards in several different regulatory sections. These notification 
procedures for alternative actions are comparable to the existing 
notification requirements in subpart O for the integrity management 
regulations. Because PHMSA is expanding the use of notifications to 
pipeline segments for which subpart O does not apply (i.e., to non-HCA 
pipeline segments), PHMSA is adding a new Sec.  192.18 in subpart A 
that contains the procedure for submitting such notifications for any 
pipeline segment.

Sec.  192.67 Records: Material Properties

    Section 23 of the 2011 Pipeline Safety Act requires the Secretary 
of Transportation to require the verification of records to ensure they 
accurately reflect the physical and operational characteristics of 
certain pipelines and to confirm the established MAOP of the pipelines. 
PHMSA has determined that compliance requires that pipeline material 
properties records are complete and accurate. This final rule moves the 
original Sec.  192.67 to Sec.  192.69 and adds in its place a new Sec.  
192.67 that requires each operator of gas transmission pipelines 
installed after the effective date of this final rule to collect or 
make, and retain for the life of the pipeline, records that document 
the physical characteristics of the pipeline, including tests, 
inspections, and attributes required by the manufacturing specification 
in effect at the time the pipe was manufactured. The physical 
characteristics an operator must keep documented include diameter, 
yield strength, ultimate tensile strength, wall thickness, seam type, 
and chemical composition. These requirements also apply to any new 
materials or components that are put on existing pipelines. For 
pipelines installed prior to the effective date of this final rule, 
operators are required to retain for the life of the pipeline all such 
records in their possession as of the effective date of this final 
rule. These recordkeeping requirements apply to offshore gathering 
lines and Type A gathering lines in accordance with Sec.  192.9.
    Pipelines that lack the traceable, verifiable, and complete records 
needed to substantiate MAOP may be subject to the MAOP reconfirmation 
requirements at Sec.  192.624, as specified in that section.

Sec.  192.69 Storage and Handling of Plastic Pipe and Associated 
Components

    Previous Sec.  192.67, titled ``Storage and handling of plastic 
pipe and associated components,'' was created as a part of the Plastic 
Pipe rule, which was published on November 20, 2018 (83 FR 58716). 
PHMSA is redesignating that section in this final rule to a new Sec.  
192.69. No other changes have been made to the section.

Sec.  192.127 Records: Pipe Design

    Section 23 of the 2011 Pipeline Safety Act requires the Secretary 
of Transportation to require the verification of records to ensure they 
accurately reflect the physical and operational characteristics of 
certain pipelines and to confirm the established MAOP of the pipelines. 
PHMSA has determined that compliance requires that pipe design records 
are complete and accurate. For pipelines installed after the effective 
date of this final rule, this final rule adds a new Sec.  192.127 to 
require each operator of gas transmission pipelines to collect or make, 
and retain for the life of the pipeline, records documenting pipe 
design to withstand anticipated external pressures and determination of 
design pressure for steel pipe. For pipelines installed prior to the 
effective date of this final rule, operators are required to retain for 
the life of the pipeline all such records in their possession as of the 
effective date of this final rule. Pipelines that lack the traceable, 
verifiable, and complete records needed to substantiate MAOP may be 
subject to the MAOP reconfirmation requirements at Sec.  192.624, as 
specified in that section.

Sec.  192.150 Passage of Internal Inspection Devices

    The current pipeline safety regulations in Sec.  192.150 require 
that pipelines be designed and constructed to accommodate in-line 
inspection devices. Prior to this rulemaking, part 192 was silent on 
technical standards or guidelines for implementing requirements to 
assure pipelines are designed and constructed for in-line inspection 
assessments. Previously, there was no consensus industry standard that 
addressed design and construction requirements for in-line inspection 
assessments. NACE Standard Practice, NACE SP0102-2010, ``In-line 
Inspection of Pipelines,'' has since been published and provides 
guidance on this issue in section 7. The incorporation of this standard 
into the Federal Pipeline Safety Regulations at Sec.  192.150 will 
promote a higher level of safety by establishing consistent standards 
for the design and construction of pipelines to accommodate in-line 
inspection devices.

Sec.  192.205 Records: Pipeline Components

    Section 23 of the 2011 Pipeline Safety Act requires the Secretary 
of Transportation to require the verification of records to ensure they 
accurately reflect the physical and operational characteristics of 
certain pipelines and to confirm the established MAOP of the pipelines. 
PHMSA has determined that compliance requires that pipeline component 
records are complete and accurate. For pipelines installed after the 
effective date of this final rule, this final rule adds a new Sec.  
192.205 to require each operator of gas transmission pipelines to 
collect or make, and retain for the operational life of the component, 
records documenting manufacturing and testing information for valves 
and other pipeline components. For pipelines installed prior to the 
effective date of this final rule, operators are required to retain for 
the life of the pipeline all such records in their possession as of the 
effective date of this final rule. Pipelines that lack the traceable, 
verifiable, and complete records needed to substantiate MAOP may be 
subject to the MAOP reconfirmation requirements at Sec.  192.624, as 
specified in that section.

Sec.  192.227 Qualification of Welders

    Section 23 of the 2011 Pipeline Safety Act requires the Secretary 
of Transportation to require the verification of records to ensure they 
accurately reflect the physical and operational characteristics of 
certain pipelines and to confirm the established MAOP of the pipelines. 
PHMSA has determined that compliance requires that pipeline welding 
qualification records are complete and accurate. This final rule adds a 
new paragraph, Sec.  192.227(c), to require each operator of gas 
transmission pipelines to make and retain records demonstrating each 
individual welder's qualification in accordance with this section for a 
minimum of 5 years following construction. This requirement will apply 
to pipelines installed after one year from the effective date of the 
rule.

Sec.  192.285 Plastic Pipe: Qualifying Persons To Make Joints

    Section 23 of the 2011 Pipeline Safety Act requires the Secretary 
of Transportation to require the verification of records to ensure they 
accurately reflect the physical and

[[Page 52233]]

operational characteristics of certain pipelines and to confirm the 
established MAOP of the pipelines. PHMSA has determined that compliance 
requires that plastic pipeline qualification records are complete and 
accurate. This final rule adds a new paragraph, Sec.  192.285(e), to 
require each operator of gas transmission pipelines to make and retain 
records demonstrating a person's plastic pipe joining qualifications in 
accordance with this section for a minimum of 5 years following 
construction. This requirement will apply to pipelines installed after 
one year from the effective date of the rule.

Sec.  192.493 In-Line Inspection of Pipelines

    The current pipeline safety regulations at Sec. Sec.  192.921 and 
192.937 require that operators assess the material condition of 
pipelines in certain circumstances (e.g., IM assessments for pipelines 
in HCAs) and allow the use of ILI tools for these assessments. 
Operators of gas transmission pipelines are required to follow the 
requirements of ASME/ANSI B31.8S, ``Managing System Integrity of Gas 
Pipelines,'' in conducting their IM activities. ASME B31.8S provides 
limited guidance for conducting ILI assessments. Presently, part 192 is 
silent on the technical standards or guidelines for performing ILI 
assessments or implementing these requirements. When the IM regulations 
were initially promulgated, there were no uniform industry standards 
for ILI assessments. Three related standards have since been published:
     API STD 1163-2013, ``In-Line Inspection Systems 
Qualification Standard.'' This Standard serves as an umbrella document 
to be used with and as a complement to the NACE and ASNT standards 
below, which are incorporated by reference in API STD 1163.
     NACE Standard Practice, NACE SP0102-2010, ``In-line 
Inspection of Pipelines.''
     ANSI/ASNT ILI-PQ-2005 (2010), ``In-line Inspection 
Personnel Qualification and Certification.''
    API 1163-2013 is more comprehensive and rigorous than the current 
requirements in 49 CFR part 192. The incorporation of this standard 
into the Federal Pipeline Safety Regulations will promote a higher 
level of safety by establishing consistent standards to qualify the 
equipment, people, processes, and software utilized by the ILI 
industry. The API standard addresses in detail each of the following 
aspects of ILI inspections, most of which are not currently addressed 
in the regulations:
     Systems qualification process.
     Personnel qualification.
     ILI system selection.
     Qualification of performance specifications.
     System operational validation.
     System results qualification.
     Reporting requirements.
     Quality management system.
    The NACE standard covers in detail each of the following aspects of 
ILI assessments, most of which are not currently addressed in part 192 
or in ASME B31.8S:
     Tool selection.
     Evaluation of pipeline compatibility with ILI.
     Logistical guidelines, which includes survey acceptance 
criteria and reporting.
     Scheduling.
     New construction (planning for future ILI in new lines).
     Data analysis.
     Data management.
    The NACE standard provides a standardized questionnaire and 
specifies that the completed questionnaire should be provided to the 
ILI vendor. The questionnaire lists relevant parameters and 
characteristics of the pipeline section to be inspected. PHMSA 
determined that the consistency, accuracy, and quality of pipeline in-
line inspections would be improved by incorporating the consensus NACE 
standard into the regulations.
    The NACE standard applies to ``free swimming'' inspection tools 
that are carried down the pipeline by the transported product. It does 
not apply to tethered or remotely controlled ILI tools, which can also 
be used in special circumstances (e.g., examination of laterals). While 
their use is less prevalent than free-swimming tools, some pipeline IM 
assessments have been conducted using tethered or remotely controlled 
ILI tools. PHMSA determined that many of the provisions in the NACE 
standard can be applied to tethered or remotely controlled ILI tools. 
Therefore, PHMSA is amending the Federal Pipeline Safety Regulations to 
allow the use of these tools, provided they comply with the applicable 
sections of the NACE standard.
    The ANSI/ASNT standard provides for qualification and certification 
requirements that are not addressed by 49 CFR part 192. The 
incorporation of this standard into the regulations will promote a 
higher level of safety by establishing consistent standards to qualify 
the equipment, people, processes and software utilized by the ILI 
industry. The ANSI/ASNT standard addresses in detail each of the 
following aspects, which are not currently addressed in the 
regulations:
     Requirements for written procedures.
     Personnel qualification levels.
     Education, training and experience requirements.
     Training programs.
     Examinations (testing of personnel).
     Personnel certification and recertification.
     Personnel technical performance evaluations.
    The final rule adds a new Sec.  192.493 to require compliance with 
the three consensus standards discussed above when conducting ILI of 
pipelines.

Sec.  192.506 Transmission Lines: Spike Hydrostatic Pressure Test

    A pressure test that incorporates a short duration ``spike'' 
pressure is a proven means to confirm the strength of pipe with known 
or suspected threats of cracks or crack-like defects (e.g., stress 
corrosion cracking, longitudinal seam defects, etc.). Currently, part 
192 does not include minimum standards for such a spike hydrostatic 
pressure test. This final rule adds a new Sec.  192.506 to codify the 
minimum standards for performing spike hydrostatic pressure tests when 
operators are required to, or elect to, use this assessment method. 
Under the spike hydrostatic pressure test requirements, an operator may 
use other technologies or processes equivalent to a spike hydrostatic 
pressure test with justification and notification in accordance with 
Sec.  192.18.

Sec.  192.517 Records: Tests

    Section 192.517 prescribes the recordkeeping requirements for each 
test performed under Sec. Sec.  192.505 and 192.507. PHMSA is making 
conforming amendments to Sec.  192.517 to add the recordkeeping 
requirements for the new Sec.  192.506.

Sec.  192.607 Verification of Pipeline Material Properties and 
Attributes: Onshore Steel Transmission Pipelines

    Section 23 of the 2011 Pipeline Safety Act mandates the Secretary 
of Transportation to require operators of gas transmission pipelines in 
Class 3 and Class 4 locations and Class 1 and Class 2 locations in HCAs 
to verify records to ensure the records accurately reflect the physical 
and operational characteristics of the pipelines and confirm the MAOP 
of the pipelines established by the operator (49 U.S.C. 60139). PHMSA 
issued Advisory Bulletin 11-01 on January 10, 2011 (76

[[Page 52234]]

FR 1504), and Advisory Bulletin 12-06 on May 7, 2012 (77 FR 26822), to 
inform operators of this requirement. Operators have submitted 
information in their Annual Reports (starting for calendar year 2012) 
indicating that a portion of transmission pipeline segments do not have 
adequate records to establish MAOP and that some operators do not have 
traceable, verifiable, and complete records that accurately reflect the 
physical and operational characteristics of the pipeline. Therefore, 
PHMSA has determined that additional regulations are needed to 
implement the 2011 Pipeline Safety Act. This final rule promulgates 
specific criteria for determining which pipeline segments must undergo 
examinations and tests to understand and document physical and material 
properties and reconfirm a proper MAOP. For operators that do not have 
traceable, verifiable, and complete documentation for the physical 
pipeline characteristics and attributes of a pipeline segment, PHMSA is 
adding a new Sec.  192.607 that contains the procedure for verifying 
and documenting pipeline physical properties and attributes that are 
not documented in traceable, verifiable, and complete records and to 
establish standards for performing these actions. For operators of 
certain pipelines lacking the necessary records to substantiate MAOP, 
PHMSA is also adding Sec.  192.624, which provides operators several 
methods for reconfirming a pipeline segment's MAOP.
    The new material properties verification requirements at Sec.  
192.607 include the scope of information needed and the methodology for 
verifying material properties and attributes of pipelines. The most 
difficult information to obtain, from a technical perspective, is the 
strength of the pipeline's steel. Conventional techniques to obtain 
that data would include cutting out a piece of pipe and destructively 
testing it to determine the yield and ultimate tensile strength. In 
this final rule, PHMSA is providing operators with flexibility by 
allowing the use of non-destructive techniques that have been validated 
to produce accurate results for the grade and type of pipe being 
evaluated (see Sec.  192.624).
    Another issue regarding material properties verification is the 
cost associated with excavating the pipeline to verify material 
properties and determining how much pipeline needs to be exposed and 
tested to have assurance of the accuracy of the verification. PHMSA 
addresses these issues within this final rule by specifying that 
operators can take advantage of opportunities when the pipeline is 
already being exposed, such as when maintenance activity is occurring 
and when anomaly repairs are being made, to verify material properties 
that are not documented in traceable, verifiable, and complete records. 
For example, PHMSA considers excavations associated with the direct 
examination of anomalies, pipeline relocations at road crossings and 
river or stream crossings, pipe upgrades for class location changes, 
pipe cut-outs for hydrostatic pressure tests, and excavations where 
pipe is replaced due to anomalies to be opportunities to perform 
material properties verification. Over time, pipeline operators will 
develop a substantial set of traceable, verifiable, and complete 
material properties data, which will provide assurance that material 
properties are reliably known for the population of segments that did 
not have pipeline physical properties and attributes documented in 
traceable, verifiable, and complete records previously. Through this 
final rule, PHMSA is requiring that operators continue this 
opportunistic material properties verification process until the 
operator has completed enough verifications to obtain a high level of 
confidence that only a small percentage of pipeline segments have 
physical pipeline characteristics and attributes that are not verified 
or are otherwise inconsistent with all available information or 
operators' past assumptions. This final rule specifies the number of 
excavations required for operators to achieve this level of confidence.
    Operators may use an alternative sampling approach that differs 
from the sampling approach specified in the requirements if they notify 
PHMSA in advance of using an alternative sampling approach in 
accordance with Sec.  192.18.
    Requirements are also included in the material properties 
verification section to ensure that operators document the results of 
the material properties verification process in records that must be 
retained for the life of the pipeline.

Sec.  192.619 Maximum Allowable Operating Pressure: Steel or Plastic 
Pipelines

    The NTSB report on the PG&E incident included a recommendation (P-
11-15) that PHMSA amend its 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 MAOP. This final rule revises the test 
pressure factors in Sec.  192.619(a)(2)(ii) to correspond to at least 
1.25 times MAOP for pipelines installed after the effective date of 
this rule.
    The NTSB also recommended repealing Sec.  192.619(c), commonly 
referred to as the ``grandfather clause,'' and requiring that all gas 
transmission pipelines constructed before 1970 be subjected to a 
hydrostatic pressure test that incorporates a spike test 
(recommendation P-11-14). Similarly, section 23 of the 2011 Pipeline 
Safety Act requires that selected pipeline segments in certain 
locations with previously untested pipe (i.e., the MAOP is established 
under Sec.  192.619(c)) or without MAOP records be tested with a 
pressure test or equivalent means to reconfirm the pipeline's MAOP. 
These requirements are addressed in the new Sec.  192.624 and are 
described in more detail in the following section. This final rule also 
makes conforming changes to Sec.  192.619 to require that operators of 
pipeline segments to which Sec.  192.624 applies establish and document 
the segment's MAOP in accordance with Sec.  192.624.

Sec.  192.624 Maximum Allowable Operating Pressure Reconfirmation: 
Onshore Steel Transmission Pipelines

    Section 23 of the 2011 Pipeline Safety Act requires the 
verification of records for pipe in Class 3 and Class 4 locations, and 
high-consequence areas in Class 1 and Class 2 locations, to ensure they 
accurately reflect the physical and operational characteristics of the 
pipelines and confirm the established MAOP of the pipelines. Operators 
have submitted information in annual reports (beginning in calendar 
year 2012) indicating that some gas transmission pipeline segments do 
not have adequate material properties records or testing records to 
confirm physical and operational characteristics and to establish MAOP. 
For these pipelines, the 2011 Pipeline Safety Act requires that PHMSA 
promulgate regulations to require operators to reconfirm MAOP as 
expeditiously as economically feasible. The statute also requires PHMSA 
to issue regulations that require previously untested pipeline segments 
located in HCAs and operating at greater than 30 percent SMYS be tested 
to confirm the material strength of the pipelines. Such tests must be 
performed by pressure testing or other methods determined by the 
Secretary to be of equal or greater effectiveness.
    As a result of its investigation of the PG&E incident, the NTSB 
issued two related recommendations. NTSB recommended that PHMSA repeal 
Sec.  192.619(c), commonly referred to as

[[Page 52235]]

the ``grandfather clause,'' and require that all gas transmission 
pipelines constructed before 1970 be subjected to a hydrostatic 
pressure test that incorporates a spike test (P-11-14). The NTSB also 
recommended that PHMSA amend the Federal Pipeline Safety Regulations so 
that manufacturing- and construction-related defects can only be 
considered stable if a pipeline has been subjected to a post-
construction hydrostatic pressure test of at least 1.25 times the MAOP 
(P-11-15).
    Through this final rule, PHMSA is finalizing a new Sec.  192.624 to 
address these mandates and recommendations. This final rule requires 
that operators reconfirm and document MAOP for certain onshore steel 
gas transmission pipelines located in HCAs or MCAs that meet one or 
more of the criteria specified in Sec.  192.624(a). More specifically, 
this section applies to (1) pipelines in HCAs or Class 3 or Class 4 
locations lacking traceable, verifiable, and complete records necessary 
to establish the MAOP (per Sec.  192.619(a)) for the pipeline segment, 
including, but not limited to, hydrostatic pressure test records 
required by Sec.  192.517(a); and (2) pipelines where the MAOP was 
established in accordance with Sec.  192.619(c), the pipeline segment's 
MAOP is greater than or equal to 30 percent of SMYS, and the pipeline 
is located in an HCA, a Class 3 or Class 4 location, or an MCA that can 
accommodate inspection by means of instrumented inline inspection tools 
(i.e., ``smart pigs''). This approach implements the mandate in the 
2011 Pipeline Safety Act for pipeline segments in HCAs and Class 3 and 
Class 4 locations (49 U.S.C. 60139). In addition, the scope includes 
pipeline segments in the newly defined MCAs. This approach is intended 
to address the NTSB recommendations and to provide increased safety in 
areas where a pipeline rupture would have a significant impact on the 
public or the environment. Though PHMSA is subjecting certain 
grandfathered pipeline segments to the MAOP reconfirmation requirements 
of Sec.  192.624, PHMSA is not repealing Sec.  192.619(c) for pipeline 
segments located outside of HCAs, Class 3 or Class 4 locations, or MCAs 
that can accommodate inspection by means of instrumented ILI tools. 
Previously grandfathered pipelines that reconfirm MAOP using one of the 
methods of Sec.  192.624 that operate above 72 percent SMYS may 
continue to operate at the reconfirmed pressure.
    The methods to reconfirm MAOP are specified in Sec.  192.624 and 
are as follows:
    Method 1--Pressure test. The pressure test method as specified in 
section 23 of the 2011 Pipeline Safety Act. Operators choosing to 
pressure test must also verify material property records in accordance 
with Sec.  192.607. PHMSA notes that a pressure test requires the 
cutout of pipe at test manifold sites and those pipe cutouts would be a 
prime example of pipe that could and should be tested through the 
material properties verification procedure, if necessary. In accordance 
with the statute, PHMSA determined that the following methods (2) 
through (6) are equally effective as a pressure test for the purposes 
of reconfirming MAOP.
    Method 2--Pressure reduction. De-rating the pipeline segment so 
that the new MAOP is less than the historical actual sustained 
operating pressure by using a pressure test safety factor of 0.80 (for 
Class 1 and Class 2 locations) or 0.67 (for Class 3 and Class 4 
locations) times the sustained operating pressure (equivalent to a 
pressure test using gas or water as the test medium with a test 
pressure of 1.25 times MAOP for Class 1 and Class 2 locations and 1.5 
times MAOP for Class 3 and Class 4 locations).
    Method 3--Engineering critical assessment. An in-line inspection, 
previously performed pressure test, or alternative technology and 
engineering critical assessment process using technical analysis with 
acceptance criteria to establish a safety margin equivalent to that 
provided by a new pressure test. PHMSA organized the ECA process 
requirements under a new Sec.  192.632 and established the technical 
requirements for analyzing the predicted failure pressure as a part of 
the ECA analysis in a new Sec.  192.712. If an operator chooses the ECA 
method for MAOP reconfirmation but does not have any of the material 
properties necessary to perform an ECA analysis (diameter, wall 
thickness, seam type, grade, and Charpy V-notch toughness values, if 
applicable), the operator must include the pipeline segment in its 
program to verify the undocumented information in accordance with the 
material properties verification requirements at Sec.  192.607.
    Method 4--Pipe replacement. Replacement of the pipe, which would 
require a new pressure test that conforms with subpart J before the 
pipe is placed into service.
    Method 5--Pressure reduction for pipeline segments with small 
potential impact radii. For pipeline segments with a potential impact 
radius of less than or equal to 150 feet, a pressure reduction using a 
safety factor of 0.90 times the sustained operating pressure is allowed 
(equivalent to a pressure test of 1.11 times MAOP), supplemented with 
additional preventive and mitigative measures specified in this final 
rule.
    Method 6--Alternative technology. Other technology that the 
operator demonstrates provides an equivalent or greater level of 
safety, provided PHMSA is notified in advance in accordance with Sec.  
192.18.
    Lastly, this final rule includes a new paragraph, Sec.  192.624(f), 
to clearly specify that records created while reconfirming MAOP must be 
retained for the life of the pipeline.

Sec.  192.632 Engineering Critical Assessment for Maximum Allowable 
Operating Pressure Reconfirmation: Onshore Steel Transmission Pipelines

    The requirements for reconfirming MAOP in the new Sec.  192.624 
include an option for operators to perform an engineering critical 
assessment, or ECA, to reconfirm MAOP in lieu of pressure testing and 
the other methods provided. The requirements for conducting such an ECA 
were proposed under the MAOP reconfirmation requirements at Sec.  
192.624(c)(3); however, PHMSA has moved the ECA requirements to a new, 
stand-alone section and cross-referenced those requirements in order to 
improve the readability of the MAOP reconfirmation requirements.
    Operators choosing the ECA method for MAOP reconfirmation may 
perform an in-line inspection and a technical analysis with acceptance 
criteria to establish a safety margin equivalent to that provided by a 
pressure test. PHMSA established the technical requirements for 
analyzing the predicted failure pressure as a part of the ECA analysis 
in a new Sec.  192.712, and those requirements are cross-referenced 
within this ECA process.
    Although PHMSA expects that most operators will use an ECA in 
conjunction with in-line inspection, PHMSA would also allow operators 
with past, valid pressure tests to calculate the largest defects that 
could have survived the pressure test and analyze the postulated 
defects to calculate a predicted failure pressure with which to 
establish MAOP. This approach might be desirable for operators in 
certain circumstances, such as for line segments that have valid 
pressure test records, but that lack other records (such as material 
strength or pipe wall thickness) necessary to determine design pressure 
and establish MAOP under the existing Sec.  192.619(a). Another 
situation for which operators could use this approach would be if the 
operator has a valid pressure test, but it was not conducted at a test 
pressure that

[[Page 52236]]

was high enough to establish the current MAOP.
    Operators with pressure test records meeting the subpart J test 
requirements may use an ECA by calculating the largest defect that 
could have survived the pressure test and estimating the flaw growth 
between the date of the test and the date of the ECA. The ECA is then 
performed using these postulated defect sizes. In addition, operators 
must calculate the remaining life of the most severe defects that could 
have survived the pressure test and establish an appropriate re-
assessment interval in accordance with new Sec.  192.712.
    If an operator chooses to use ILI to characterize the defects 
remaining in the pipe segment and the ECA method for MAOP 
reconfirmation but does not have one or more of the material properties 
necessary to perform an ECA analysis (diameter, wall thickness, seam 
type, grade, and Charpy V-notch toughness values, if applicable), the 
operator must use conservative assumptions and include the pipeline 
segment in its program to verify the undocumented information in 
accordance with the material properties verification requirements at 
Sec.  192.607.

Sec.  192.710 Transmission Lines: Assessments Outside of High 
Consequence Areas

    Section 5 of the 2011 Pipeline Safety Act requires, if appropriate, 
the Secretary of Transportation to issue regulations expanding IM 
system requirements, or elements thereof, beyond HCAs. Currently, part 
192 does not contain any requirement for operators to conduct integrity 
assessments of onshore transmission pipelines that are not HCA 
segments, as defined in Sec.  192.903, and are therefore not subject to 
subpart O. However, only approximately 7 percent of onshore gas 
transmission pipelines are located in HCAs. Through this final rule, 
operators are required to periodically assess Class 3 locations, Class 
4 locations, and MCAs that can accommodate inspection by means of an 
instrumented inline inspection tool. The periodic assessment 
requirements under this section apply to pipelines in these locations 
with MAOPs greater than or equal to 30 percent of SMYS.
    Industry has, as a practical matter, assessed portions of pipelines 
in non-HCA segments coincident with integrity assessments of HCA 
pipeline segments. For example, INGAA has noted in comment submissions 
that approximately 90 percent of Class 3 and Class 4 mileage not in 
HCAs are presently assessed during IM assessments. This is because, in 
large part, ILI or pressure testing, by their nature, assess large 
continuous pipeline segments that may contain some HCA segments but 
that could also contain significant amounts of non-HCA segments.
    While INGAA does not represent all pipeline operators subject to 
part 192, it does represent the majority of gas transmission operators. 
PHMSA has determined that, given this level of assessment, it is 
appropriate and consistent with industry direction to codify 
requirements for operators to periodically assess certain gas 
transmission pipelines outside of HCAs to monitor for, detect, and 
remediate pipeline defects and anomalies. Additionally, to achieve the 
desired outcome of performing assessments in areas where people live, 
work, or congregate, while minimizing the cost of identifying such 
locations, PHMSA is basing the requirements for identifying those 
locations on processes already being implemented by pipeline operators. 
More specifically, the MCA definition assumes a similar process used 
for identifying HCAs, with the exception that the threshold for 
buildings intended for human occupancy located within the potential 
impact circle is reduced from 20 to 5.
    Because significant non-HCA pipeline mileage has been previously 
assessed in conjunction with the regular assessment of HCA pipeline 
segments, PHMSA is allowing operators to count those prior assessments 
as compliant with the new Sec.  192.710 for the purposes of assessing 
non-HCAs if those assessments were conducted, and threats remediated, 
in conjunction with an integrity assessment required by subpart O.
    This final rule also requires that the assessment required by the 
new Sec.  192.710 be conducted using the same methods as adopted for 
HCAs (see Sec.  192.921, below). Operators may use ``other technology'' 
as an assessment method, provided the operator notifies PHMSA in 
accordance with Sec.  192.18.

Sec.  192.712 Analysis of Predicted Failure Pressure

    The new requirements for reconfirming MAOP in the new Sec.  192.624 
include an option for operators to perform an engineering critical 
assessment, or ECA, to reconfirm MAOP in lieu of pressure testing and 
the other methods provided. A key aspect of the ECA analysis is the 
detailed analysis of the remaining strength of pipe with known or 
assumed defects. The current Federal Pipeline Safety Regulations in 
subparts I and O refer to methods for predicting the failure pressure 
for pipe with corrosion metal loss defects. However, the regulations 
are silent on performing such analysis for pipe with cracks (including 
crack-like defects such as selective seam weld corrosion). Therefore, 
in this final rule, PHMSA is inserting a new section to address the 
techniques and procedures for analyzing the predicted failure pressures 
for pipe with corrosion metal loss and cracks or crack-like defects. 
Examples of technically proven models for calculating predicted failure 
pressures include: For the brittle failure mode, the Newman-Raju Model 
\87\ and PipeAssess PITM software; \88\ and for the ductile 
failure mode, Modified Log-Secant Model,\89\ API RP 579-1 \90\--Level 
II or Level III, CorLasTM software,\91\ PAFFC Model,\92\ and 
PipeAssess PITM software. All failure models used for the 
ECA analysis must be used within its technical parameters for the 
defect type and the pipe or weld material properties. Conforming 
changes are being made to applicable sections in subparts I and O to 
refer to this new section, for consistency, but the basic techniques 
are unchanged.
---------------------------------------------------------------------------

    \87\ Newman, J.C., and Raju; ``Stress Intensity Factors for 
Cracks in Three Dimensional Finite Bodies Subjected to Tension and 
Bending Loads;'' Computational Methods in the Mechanics of Fracture; 
Elsevier; 1986; pp. 311-334.
    \88\ Interim Report for Phase II--Task 5 of the Comprehensive 
Study to Understand Longitudinal ERW Seam Failures, ``Summary Report 
for an Integrity Management Software Tool,'' May 2017. https://primis.phmsa.dot.gov/matrix/FilGet.rdm?fil=11469.
    \89\ ASTM International, ASTM STP 536, ``Failure Stress Levels 
of Flaws in Pressurized Cylinders,'' 1973.
    \90\ American Petroleum Institute and American Society of 
Mechanical Engineers, API 579-1/ASME FFS-1, ``Fitness-For-Service,'' 
Second Edition, June 2007.
    \91\ NACE International, NACE Corrosion 96 Paper 255, ``Effect 
of Stress Corrosion Cracking on Integrity and Remaining Life of 
Natural Gas Pipelines,'' March 1996.
    \92\ Pipeline Research Council International, Inc., Topical 
Report NG-18 No. 193, ``Development and Validation of a Ductile Flaw 
Growth Analysis for Gas Transmission Line Pipe,'' June 1991.
---------------------------------------------------------------------------

    As a part of this section, PHMSA is including a new paragraph to 
address cracks and crack-like defects, which as stated above is a 
critical function of the ECA analysis. The ECA analysis requires the 
conservative analysis of any in-service cracks, crack-like defects 
remaining in the pipe, or the largest possible crack that could remain 
in the pipe, including crack dimensions (length and depth) to determine 
the predicted failure pressure (PFP) of each defect; the failure mode 
(ductile, brittle, or both) for the microstructure; the defect's 
location and type; the pipeline's operating conditions (including 
pressure cycling); and failure stress and

[[Page 52237]]

crack growth analysis to determine the remaining life of the pipeline. 
An ECA must use the techniques and procedures developed and confirmed 
through the research findings provided by PHMSA and other reputable 
technical sources for longitudinal seam and crack growth, such as the 
Comprehensive Study to Understand Longitudinal ERW Seam Research & 
Development study task reports: Battelle Final Reports (``Battelle's 
Experience with ERW and Flash Weld Seam Failures: Causes and 
Implications''--Task 1.4), Report No. 13-002 (``Models for Predicting 
Failure Stress Levels for Defects Affecting ERW and Flash-Welded 
Seams''--Subtask 2.4), Report No. 13-021 (``Predicting Times to Failure 
for ERW Seam Defects that Grow by Pressure-Cycle-Induced Fatigue''--
Subtask 2.5), and ``Final Summary Report and Recommendations for the 
Comprehensive Study to Understand Longitudinal ERW Seam Failures--Phase 
1''--Task 4.5), which can be found online at: https://primis.phmsa.dot.gov/matrix/PrjHome.rdm?prj=390. Operators wanting to 
use assumed Charpy V-notch toughness values differing from the 
prescribed values as a part of fracture mechanics analysis must notify 
PHMSA in accordance with Sec.  192.18.

Sec.  192.750 Launcher and Receiver Safety

    PHMSA has determined that more explicit requirements are needed for 
safety when performing maintenance activities that use launchers and 
receivers to insert and remove maintenance tools and devices, as such 
facilities are subject to pipeline system pressures. The current 
regulations for hazardous liquid pipelines at 49 CFR part 195 have, 
since 1981, contained such safety requirements for scraper and sphere 
facilities (Sec.  195.426). However, the regulations for natural gas 
pipelines do not similarly require controls or instrumentation to 
protect against inadvertent breaches of system integrity due to the 
incorrect operation of launchers and receivers for ILI tools, scraper, 
and sphere facilities. Accordingly, this final rule is adding a new 
Sec.  192.750 to require a suitable means to relieve pressure in the 
barrel and either a means to indicate the pressure in the barrel or a 
means to prevent opening if pressure has not been relieved.

Sec.  192.805 Qualification Program

    PHMSA is revising the Federal Pipeline Safety Regulations to 
include a new Sec.  192.18 that provides instructions for submitting 
notifications to PHMSA whenever required by part 192. PHMSA is making 
conforming changes to Sec.  192.805 to refer to the new Sec.  192.18.

Sec.  192.909 How can an operator change its integrity management 
program?

    PHMSA is revising the Federal Pipeline Safety Regulations to 
include a new Sec.  192.18 that provides instructions for submitting 
notifications to PHMSA whenever required by part 192. PHMSA is making 
conforming changes to Sec.  192.909 to refer to the new Sec.  192.18.

Sec.  192.917 How does an operator identify potential threats to 
pipeline integrity and use the threat identification in its integrity 
program?

    Section 29 of the 2011 Pipeline Safety Act requires operators to 
consider seismicity when evaluating threats. Accordingly, PHMSA is 
revising Sec.  192.917(a)(3) to include seismicity of the area in 
evaluating the threat of outside force damage. To address NTSB 
recommendation P-11-15, PHMSA is also revising the criteria in Sec.  
192.917(e)(3) for addressing the threat of manufacturing and 
construction defects by requiring that a pipeline segment must have 
been pressure tested to a minimum of 1.25 times MAOP to conclude latent 
defects are stable. Section 192.917(e)(4) has additional requirements 
for the assessment of low-frequency ERW pipe with seam failures. It now 
requires usage of the appropriate technology to assess low-frequency 
ERW pipe, including seam cracking and selective seam weld corrosion. 
Pipe with seam cracks must be evaluated using fracture mechanics 
modeling for failure stress pressures and cyclic fatigue crack growth 
analysis to estimate the remaining life of the pipe in accordance with 
Sec.  192.712.
    Lastly, the integrity management requirements to address specific 
threats in Sec.  192.917(e) include requirements for the major causes 
of pipeline incidents, such as corrosion, third-party damage, cyclic 
fatigue, manufacturing and construction defects, and electric 
resistance welded pipe. However, Sec.  192.917(e) does not address 
cracks and crack-like defects. Therefore, PHMSA is adding a new 
paragraph, Sec.  192.917(e)(6), to include specific IM requirements for 
addressing the threat of cracks and crack-like defects (including, but 
not limited to, stress corrosion cracking or other environmentally 
assisted cracking, seam defects, selective seam weld corrosion, girth 
weld cracks, hook cracks, and fatigue cracks) comparable to the other 
types of threats addressed in Sec.  192.917(e).

Sec.  192.921 How is the baseline assessment to be conducted?

    Section 192.921 requires that pipelines subject to the IM 
regulations have an integrity assessment. The current regulations allow 
operators to use ILI tools; pressure testing in accordance with subpart 
J; direct assessment for the threats of external corrosion, internal 
corrosion, and stress corrosion cracking; and other technology that the 
operator demonstrates provides an equivalent level of understanding of 
the condition of the pipeline. Following the PG&E incident, PHMSA 
determined that the baseline assessment methods should be clarified and 
strengthened to emphasize ILI use and pressure testing over direct 
assessment. At San Bruno, PG&E relied heavily on direct assessment 
under circumstances for which direct assessment was not effective nor 
appropriate for the pipeline seam type and the threats to the pipeline. 
Therefore, this final rule requires that direct assessment only be 
allowed to assess the threats for which the specific direct assessment 
process is appropriate.
    This final rule also adds three additional assessment methods for 
operators to use: (1) A ``spike'' hydrostatic pressure test, which is 
particularly well-suited to address time-dependent threats, such as 
stress corrosion cracking and other cracking or crack-like defects that 
can include manufacturing- and construction-related defects; (2) guided 
wave ultrasonic testing (GWUT), which is particularly appropriate in 
cases where short pipeline segments, such as road or railroad 
crossings, are difficult to assess; and (3) excavation with direct in 
situ examination. Based upon the threat assessed, examples of 
appropriate non-destructive examination methods for in situ examination 
can include ultrasonic testing, phased array ultrasonic testing, 
inverse wave field extrapolation, radiography, or magnetic particle 
inspection.
    The current regulations indicate that ILI tools are an acceptable 
assessment method for the threats that the particular ILI tool type can 
assess. PHMSA is clarifying in this final rule that the use of ILI 
tools is appropriate for threats such as corrosion, deformation and 
mechanical damage (including dents, gouges, and grooves), material 
cracking and crack-like defects (e.g., stress corrosion cracking, 
selective seam weld corrosion, environmentally assisted cracking, and 
girth weld cracks), and hard spots with cracking. As discussed above, 
this final rule

[[Page 52238]]

strengthens guidance in this area by adding a new Sec.  192.493 to 
require compliance with the requirements and recommendations of API STD 
1163-2005, NACE SP0102-2010, and ANSI/ASNT ILI-PQ-2005 when conducting 
in-line inspection of pipelines. Accordingly, PHMSA revises Sec.  
192.921(a)(1) in this final rule to require compliance with Sec.  
192.493 instead of ASME B31.8S for baseline ILI assessments for covered 
segments.
    GWUT has been used by pipeline operators for several years. 
Previously, operators were required by Sec.  192.921(a)(4) to submit a 
notification to PHMSA as an ``other technology'' assessment method to 
use GWUT. In 2007, PHMSA developed guidelines for how it would evaluate 
notifications for the use of GWUT. These guidelines have been 
effectively used for over 9 years, and PHMSA has confidence that 
operators can use GWUT to assess the integrity of short segments of 
pipe against corrosion threats. In this final rule, PHMSA is 
incorporating these guidelines into a new Appendix F, which is 
referenced in Sec.  192.921. Therefore, operators would no longer be 
required to notify PHMSA to use GWUT.
    ASME B31.8S, section 6.1, describes both excavation and direct in 
situ examination as specialized integrity assessment methods applicable 
to particular circumstances:

    It is important to note that some of the integrity assessment 
methods discussed in para. 6 only provide indications of defects. 
Examination using visual inspection and a variety of nondestructive 
examination (NDE) techniques are required, followed by evaluation of 
these inspection results in order to characterize the defect. The 
operator may choose to go directly to examination and evaluation for 
the entire length of the pipeline segment being assessed, in lieu of 
conducting inspections. For example, the operator may wish to 
conduct visual examination of aboveground piping for the external 
corrosion threat. Since the pipe is accessible for this technique 
and external corrosion can be readily evaluated, performing in-line 
inspection is not necessary.

    PHMSA is clarifying its requirements to explicitly add excavation 
and direct in situ examination as an acceptable assessment method. As 
previously discussed under Sec.  192.710, PHMSA intends for operators 
to assess non-HCA pipe with the same methods as HCA pipe. Therefore, 
PHMSA has standardized the assessment methods between both the IM and 
non-IM sections. Operators wishing to use ``other technology'' 
differing from the prescribed acceptable assessment methods must notify 
PHMSA in accordance with Sec.  192.18.

Sec.  192.933 What actions must be taken to address integrity issues?

    PHMSA is revising the Federal Pipeline Safety Regulations to 
include a new Sec.  192.18 that provides instructions for submitting 
notifications to PHMSA whenever required by part 192. PHMSA is making 
conforming changes to Sec.  192.933 to refer to the new Sec.  192.18.

Sec.  192.935 What additional preventive and mitigative measures must 
an operator take?

    Section 29 of the 2011 Pipeline Safety Act requires operators to 
consider seismicity when evaluating threats. Accordingly, PHMSA is 
revising Sec.  192.935(b)(2) to include seismicity of the area when 
evaluating preventive and mitigative measures with respect to the 
threat of outside force damage.

Sec.  192.937 What is a continual process of evaluation and assessment 
to maintain a pipeline's integrity?

    Section 192.937 requires that operators continue to periodically 
assess HCA pipeline segments and periodically evaluate the integrity of 
each covered pipeline segment. PHMSA determined that conforming 
amendments would be needed to implement, and be consistent with, the 
changes discussed above for Sec.  192.921. Accordingly, this final rule 
requires that reassessments use the same assessment methods specified 
in Sec.  192.921. Operators wishing to use ``other technology'' 
differing from the prescribed acceptable assessment methods must notify 
PHMSA in accordance with Sec.  192.18.

Sec.  192.939 What are the required reassessment intervals?

    Section 192.939 specifies reassessment intervals for pipelines 
subject to IM requirements. Section 5 of the 2011 Pipeline Safety Act 
includes a technical correction that clarified that periodic 
reassessments must occur at a minimum of once every 7 calendar years, 
but that the Secretary may extend such deadline for an additional 6 
months if the operator submits written notice to the Secretary with 
sufficient justification of the need for the extension. PHMSA expects 
that any justification, at a minimum, must demonstrate that the 
extension does not pose a safety risk. In this final rule, PHMSA is 
codifying this technical correction.
    As explained in PHMSA IM FAQ-41, the maximum interval for 
reassessment may be set using the specified number of calendar years. 
The use of calendar years is specific to gas pipeline reassessment 
interval years and does not alter the actual year interval requirements 
which appear elsewhere in the code for various inspection and 
maintenance requirements.
    Additionally, PHMSA is revising Sec.  192.939 to include a new 
Sec.  192.18 that provides instructions for submitting notifications to 
PHMSA whenever required by part 192. PHMSA is making conforming changes 
to Sec.  192.939 to refer to the new Sec.  192.18.

Sec.  192.949 How does an operator notify PHMSA? (Removed and Reserved)

    This rulemaking includes several requirements that allow operators 
to notify PHMSA of proposed alternative approaches to achieving the 
objective of the minimum safety standards. This is comparable to 
existing notification requirements in subpart O for pipelines subject 
to the IM regulations. Because PHMSA is expanding the use of 
notifications to pipeline segments for which subpart O does not apply 
(i.e., to non-HCA pipeline segments), PHMSA is adding a new Sec.  
192.18 that contains the procedure for submitting such notifications. 
As such, Sec.  192.949 is no longer needed and is being removed and 
reserved.

Appendix F to Part 192--Criteria for Conducting Integrity Assessments 
Using Guided Wave Ultrasonic Testing (GWUT)

    As discussed under Sec.  192.921 above, a new Appendix F to part 
192 is needed to provide specific requirements and acceptance criteria 
for the use of GWUT as an integrity assessment method. Operators must 
apply all 18 criteria defined in Appendix F to use GWUT as an integrity 
assessment method. If an operator applies GWUT technology in a manner 
that does not conform with the guidelines in Appendix F, it would be 
considered ``other technology'' for the purposes of Sec. Sec.  192.710, 
192.921, and 192.937.

VI. Standards Incorporated by Reference

A. Summary of New and Revised Standards

    Consistent with the amendments in this document, PHMSA is 
incorporating by reference several standards as described below. Some 
of these standards are already incorporated by reference into the 
Federal Pipeline Safety Regulations and are being extended to other 
sections of the regulations. Other standards provide a technical basis 
for corresponding regulatory changes in this final rule.

[[Page 52239]]

     API STD 1163, ``In-Line Inspection Systems 
Qualification,'' Second edition, April 2013, Reaffirmed August 2018.
    This standard covers the use of ILI systems for onshore and 
offshore gas and hazardous liquid pipelines. This includes, but is not 
limited to, tethered, self-propelled, or free-flowing systems for 
detecting metal loss, cracks, mechanical damage, pipeline geometries, 
and pipeline location or mapping. The standard applies to both existing 
and developing technologies. This standard is an umbrella document that 
provides performance-based requirements for ILI systems, including 
procedures, personnel, equipment, and associated software. The 
incorporation of this standard into the Federal Pipeline Safety 
Regulations will provide rigorous processes for qualifying the 
equipment, people, processes, and software used in in-line inspections.
     ANSI/ASNT ILI-PQ-2005(2010), ``In-line Inspection 
Personnel Qualification and Certification,'' Reapproved October 11, 
2010.
    This standard establishes minimum requirements for the 
qualification and certification of in-line inspection personnel whose 
jobs demand specific knowledge of the technical principles of in-line 
inspection technologies, operations, regulatory requirements, and 
industry standards as those are applicable to pipeline systems. The 
employer-based standard includes qualification and certification for 
Levels I, II, and III. The incorporation of this standard into the 
Federal Pipeline Safety Regulations provides for certification and 
qualification requirements that are not otherwise addressed in part 192 
and will promote a higher level of safety by establishing consistent 
standards to qualify the equipment, people, processes, and software 
used in in-line inspections.
     NACE Standard Practice 0102-2010, ``In-Line Inspection of 
Pipelines,'' Revised 2010-03-13.
    This standard outlines a process of related activities that a 
pipeline operator can use to plan, organize, and execute an ILI 
project, and it includes guidelines pertaining to ILI data management 
and data analysis. This standard is intended for individuals and teams, 
including engineers, O&M personnel, technicians, specialists, 
construction personnel, and inspectors, involved in planning, 
implementing, and managing ILI projects and programs. The incorporation 
of this standard into the Federal Pipeline Safety Regulations would 
promote a higher level of safety by establishing consistent standards 
to qualify the equipment, people, processes, and software used in in-
line inspections.
    PHMSA is also extending the applicability of the following three 
currently incorporated-by-reference standards to new sections of the 
Federal Pipeline Safety Regulations:
     ASME/ANSI B16.5-2003, ``Pipe Flanges and Flanged 
Fittings,'' October 2004, IBR approved for Sec.  192.607(f).
    This standard covers pressure-temperature ratings, materials, 
dimensions, tolerances, marking, testing, and methods of designating 
openings for pipe flanges and flanged fittings. The standard includes 
requirements and recommendations regarding flange bolting, flange 
gaskets, and flange joints. This standard is intended for 
manufacturers, owners, employers, users, and others concerned with the 
specification, buying, maintenance, training, and safe use of valves 
with pressure equipment. The incorporation of this standard promotes 
industry best practices and operational, cost, and safety benefits.
     ASME/ANSI B31G-1991 (Reaffirmed 2004), ``Manual for 
Determining the Remaining Strength of Corroded Pipelines,'' 2004, IBR 
approved for Sec. Sec.  192.632(a) and 192.712(b).
    This document provides guidance for the evaluation of metal loss in 
pressurized pipelines and piping systems. It is applicable to all 
pipelines and piping systems that are part of the scope of the 
transportation pipeline codes that are part of ASME B31 Code for 
Pressure Piping, namely: ASME B31.4, Pipeline Transportation Systems 
for Liquid Hydrocarbons and Other Liquids; ASME B31.8, Gas Transmission 
and Distribution Piping Systems; ASME B31.11, Slurry Transportation 
Piping Systems; and ASME B31.12, Hydrogen Piping and Pipelines, Part 
PL.
     AGA, Pipeline Research Committee Project, PR-3-805, ``A 
Modified Criterion for Evaluating the Remaining Strength of Corroded 
Pipe,'' (December 22, 1989), IBR approved for Sec. Sec.  192.632(a) and 
192.712(b).
    This document was developed from the Modified B31G method to allow 
assessment of a river bottom profile of a corroded area on a pipeline 
to provide more accurate predictions of the pipeline's remaining 
strength, and it was adapted into a software program known as RSTRENG. 
Pipeline operators can use RSTRENG to calculate a pipeline's predicted 
failure pressure and safe pressure when determining operating pressures 
and anomaly response times.
    The incorporation by reference of ASME/ANSI B31.8S was approved for 
Sec. Sec.  192.921 and 192.937 as of January 14, 2004. That approval is 
unaffected by the section revisions in this final rule.

B. Availability of Standards Incorporated by Reference

    PHMSA currently incorporates by reference into 49 CFR parts 192, 
193, and 195 all or parts of more than 60 standards and specifications 
developed and published by standard developing organizations (SDO). In 
general, SDOs update and revise their published standards every 2 to 5 
years to reflect modern technology and best technical practices. ASTM 
often updates some of its more widely used standards every year, and 
sometimes multiple editions of standards are published in a given year.
    In accordance with the National Technology Transfer and Advancement 
Act of 1995 (Pub. L. 104-113), PHMSA has the responsibility for 
determining which currently referenced standards should be updated, 
revised, or removed, and which standards should be added to 49 CFR 
parts 192, 193, and 195. Revisions to incorporated by reference 
materials in parts 192, 193, and 195 are handled via the rulemaking 
process, which allows for the public and regulated entities to provide 
input. During the rulemaking process, PHMSA must also obtain approval 
from the Office of the Federal Register to incorporate by reference any 
new materials.
    On January 3, 2012, President Obama signed the Pipeline Safety, 
Regulatory Certainty, and Job Creation Act of 2011, Public Law 112-90. 
Section 24 of that law states: ``Beginning 1 year after the date of 
enactment of this subsection, the Secretary may not issue guidance or a 
regulation pursuant to this chapter that incorporates by reference any 
documents or portions thereof unless the documents or portions thereof 
are made available to the public, free of charge, on an internet 
website.'' 49 U.S.C. 60102(p).
    On August 9, 2013, Public Law 113-30 revised 49 U.S.C. 60102(p) to 
replace ``1 year'' with ``3 years'' and remove the phrases ``guidance 
or'' and, ``on an internet website.'' This resulted in the current 
language in 49 U.S.C. 60102(p), which now reads as follows:
    Beginning 3 years after the date of enactment of this subsection, 
the Secretary may not issue a regulation pursuant to this chapter that 
incorporates by reference any documents or portions thereof unless the 
documents or portions thereof are made available to the public, free of 
charge.

[[Page 52240]]

    On November 7, 2014, the Office of the Federal Register issued a 
final rule that revised 1 CFR 51.5 to require that Federal agencies 
include a discussion in the preamble of the final rule ``the ways the 
materials it incorporates by reference are reasonably available to 
interested parties and how interested parties can obtain the 
materials.'' 79 FR 66278. In relation to this rulemaking, PHMSA has 
contacted each SDO and has requested free public access of each 
standard that has been incorporated by reference. The SDOs agreed to 
make viewable copies of the incorporated standards available to the 
public at no cost. Pipeline operators interested in purchasing these 
standards can contact the individual and applicable standards 
organizations. The contact information is provided in this rulemaking 
action, see Sec.  192.7.
    In addition, PHMSA will provide individual members of the public 
temporary access to any standard that is incorporated by reference that 
is not otherwise available for free. Requests for access can be sent to 
the following email address: PHMSAPHPStandards@dot.gov.

VII. Regulatory Analysis and Notices

A. Statutory/Legal Authority for This Rulemaking

    This final rule is published under the authority of the Federal 
Pipeline Safety Statutes (49 U.S.C. 60101 et seq.). Section 60102 
authorizes the Secretary of Transportation to issue regulations 
governing design, installation, inspection, emergency plans and 
procedures, testing, construction, extension, operation, replacement, 
and maintenance of pipeline facilities, as delegated to the PHMSA 
Administrator under 49 CFR 1.97.
    PHMSA is revising the ``Authority'' entry for parts 191 and 192 to 
include a citation to a provision of the Mineral Leasing Act (MLA), 
specifically, 30 U.S.C. 185(w)(3). Section 185(w)(3) provides that 
``[p]eriodically, but at least once a year, the Secretary of the 
Department of Transportation shall cause the examination of all 
pipelines and associated facilities on Federal lands and shall cause 
the prompt reporting of any potential leaks or safety problems.'' The 
Secretary has delegated this responsibility to PHMSA (49 CFR 1.97). 
PHMSA has traditionally complied with Sec.  185(w)(3) through the 
issuance of its pipeline safety regulations, which require annual 
examinations and prompt reporting for all or most of the pipelines they 
cover. PHMSA is making this change to be consistent with and make clear 
its long-standing position that the agency complies with the MLA 
through the issuance of pipeline safety regulations.

B. Executive Orders 12866 and 13771, and DOT Regulatory Policies and 
Procedures

    Executive Order 12866 requires agencies to regulate in the ``most 
cost-effective manner,'' to make a ``reasoned determination that the 
benefits of the intended regulation justify its costs,'' and to develop 
regulations that ``impose the least burden on society.'' This action 
has been determined to be significant under Executive Order 12866. It 
is also considered significant under the Regulatory Policies and 
Procedures of the Department of Transportation because of substantial 
congressional, State, industry, and public interest in pipeline safety. 
The final rule has been reviewed by the Office of Management and Budget 
in accordance with Executive Order 12866 (Regulatory Planning and 
Review) and is consistent with the Executive Order 12866 requirements 
and 49 U.S.C. 60102(b)(5)-(6). Pursuant to the Congressional Review Act 
(5 U.S.C. 801 et seq., the Office of Information and Regulatory Affairs 
designated this rule as not a ``major rule,'' as defined by 5 U.S.C. 
804(2). This final rule is considered an Executive Order 13771 
regulatory action. Details on the estimated costs of this final rule 
can be found in the rule's RIA.
    The table below summarizes the annualized costs for the provisions 
in the final rule. These estimates reflect the timing of the compliance 
actions taken by operators and are annualized, where applicable, over 
21 years and discounted to 2017 using rates of 3 percent and 7 percent. 
PHMSA estimates incremental costs for the final requirements in Section 
5 of the RIA. PHMSA finds that the other final rule requirements will 
not result in an incremental cost. Additionally, PHMSA did not quantify 
the cost savings from the material properties verification provisions 
under this final rule compared to the existing regulations. The costs 
of this final rule reflect incremental integrity assessments, MAOP 
reconfirmation actions, and ILI launcher and receiver upgrades; PHMSA 
estimates the annualized cost of this rule is $32.7 million at a 7 
percent discount rate.

                 Summary of Annualized Costs, 2019-2039
                            [$2017 thousands]
------------------------------------------------------------------------
                                                  Annualized cost
                                         -------------------------------
                Provision                   3% Discount     7% Discount
                                               rate            rate
------------------------------------------------------------------------
1. MAOP Reconfirmation & Material                  $25.9           $27.9
 Properties Verification................
2. Seismicity...........................               0               0
3. Six-Month Grace Period for Seven                    0               0
 Calendar-Year Reassessment Intervals...
4. In-Line Inspection Launcher/Receiver             0.03            0.04
 Safety.................................
5. MAOP Exceedance Reports..............               0               0
6. Strengthening Requirements for                      0               0
 Assessment Methods.....................
7. Assessments Outside HCAs.............            5.48            4.71
8. Related Records Provisions...........               0               0
                                         -------------------------------
    Total...............................            31.4            32.7
------------------------------------------------------------------------

    The benefits of the final rule will depend on the degree to which 
compliance actions result in additional safety measures, relative to 
the current baseline, and the effectiveness of these measures in 
preventing or mitigating future pipeline releases or other incidents. 
For the final rule RIA, PHMSA did not monetize benefits. The rule's 
benefits are discussed qualitatively instead.
    For more information, please see the RIA in the docket for this 
rulemaking.

[[Page 52241]]

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA), as amended by the Small 
Business Regulatory Flexibility Fairness Act of 1996, requires Federal 
regulatory agencies to prepare a Final Regulatory Flexibility Analysis 
(FRFA) for any final rule subject to notice-and-comment rulemaking 
under the Administrative Procedure Act unless the agency head certifies 
that the rule will not have a significant economic impact on a 
substantial number of small entities. PHMSA prepared a FRFA which is 
available in the docket for the rulemaking.

D. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    PHMSA analyzed this final rule per the principles and criteria in 
Executive Order 13175, ``Consultation and Coordination with Indian 
Tribal Governments.'' Because this final rule would not significantly 
or uniquely affect the communities of the Indian tribal governments or 
impose substantial direct compliance costs, the funding and 
consultation requirements of Executive Order 13175 do not apply.

E. Paperwork Reduction Act

    Pursuant to 5 CFR 1320.8(d), PHMSA is required to provide 
interested members of the public and affected agencies with an 
opportunity to comment on information collection and recordkeeping 
requests. On April 18, 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. During that time, PHMSA proposed changes to 
information collections that are no longer included in this final rule. 
PHMSA determined it would be more effective to advance a rulemaking 
that focuses on the mandates from the 2011 Pipeline Safety Act and 
split out the other provisions contained in the NPRM into two other 
separate rules. As such, PHMSA has removed all references to those 
collections previously contained in the NPRM and will submit 
information collection revision requests to OMB based on the 
requirements solely contained within this final rule.
    PHMSA estimates that the proposals in this final rule will impact 
the information collections described below. These information 
collections are contained in the PSR, 49 CFR parts 190-199. The 
following information is provided for each information collection: (1) 
Title of the information collection, (2) OMB control number, (3) 
Current expiration date, (4) Type of request, (5) Abstract of the 
information collection activity, (6) Description of affected public, 
(7) Estimate of total annual reporting and recordkeeping burden, and 
(8) Frequency of collection. The information collection burden for the 
following information collections are estimated to be revised as 
follows:

    1. Title: Recordkeeping Requirements for Gas Pipeline Operators.
    OMB Control Number: 2137-0049.
    Current Expiration Date: 09/30/2021.
    Abstract: A person owning or operating a natural gas pipeline 
facility is required to maintain records, make reports, and provide 
information to the Secretary of Transportation at the Secretary's 
request. Based on the proposed revisions in this rule, 25 new 
recordkeeping requirements are being added to the pipeline safety 
regulations for owners and operators of natural gas pipelines. 
Therefore, PHMSA expects to add 24,609 responses and 3,740 hours to 
this information collection because of the provisions in this final 
rule.
    Affected Public: Natural Gas Pipeline Operators.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 3,861,470.
    Total Annual Burden Hours: 1,674,810.
    Frequency of Collection: On occasion.

    2. Title: Notification Requirements for Gas Transmission Pipeline 
Operators.
    OMB Control Number: New Collection. Will Request from OMB.
    Current Expiration Date: TBD.
    Abstract: A person owning or operating a natural gas pipeline 
facility is required to provide information to the Secretary of 
Transportation at the Secretary's request. Based on the proposed 
revisions in this rule, 10 new notification requirements are being 
added to the pipeline safety regulations for owners and operators of 
natural gas pipelines. Therefore, PHMSA expects to add 721 responses 
and 1,070 hours because of the notification requirements in this final 
rule.
    Affected Public: Gas Transmission operators.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 721.
    Total Annual Burden Hours: 1,070.
    Frequency of Collection: On occasion.

    3. Title: Annual Reports for Gas Pipeline Operators.
    OMB Control Number: 2137-0522.
    Current Expiration Date: 8/31/2020.
    Abstract: This information collection covers the collection of 
annual report data from natural gas pipeline operators. PHMSA is 
revising the Gas Transmission and Gas Gathering Annual Report (form 
PHMSA F7 100.2-1) to collect additional information including mileage 
of pipe subject to the MAOP reconfirmation and MCA criteria. Based on 
the proposed revisions, PHMSA estimates that the Annual Report will 
take an additional 5 hours per report to complete to include the newly 
required data, increasing the burden for each report to 47 burden hours 
for an overall burden increase of 7,200 burden hours across all 
operators.
    Affected Public: Natural Gas Pipeline Operators.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 10,852.
    Total Annual Burden Hours: 83,151.
    Frequency of Collection: On occasion.

    4. Title: Incident for Natural Gas Pipeline Operators.
    OMB Control Number: 2137-0635.
    Current Expiration Date: 4/30/2022.
    Abstract: This information collection covers the collection of 
incident report data from natural gas pipeline operators. PHMSA is 
revising the Gas Transmission Incident Report to have operators 
indicate whether incidents occur inside Moderate Consequence Areas. 
PHMSA does not expect there to be an increase in burden for the 
reporting of Gas Transmission incident data.
    Affected Public: Natural Gas Pipeline Operators.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 301.
    Total Annual Burden Hours: 3,612.
    Frequency of Collection: On occasion.
    Requests for copies of these information collections should be 
directed to Angela Hill or Cameron Satterthwaite, Office of Pipeline 
Safety (PHP-30), Pipeline Hazardous Materials Safety Administration 
(PHMSA), 2nd Floor, 1200 New Jersey Avenue SE, Washington, DC 20590-
0001, Telephone (202) 366-4595.

    Comments are invited on:
    (a) The need for the proposed collection of information for the 
proper performance of the functions of the agency, including whether 
the information will have practical utility;
    (b) The accuracy of the agency's estimate of the burden of the 
revised collection of information, including the validity of the 
methodology and assumptions used;
    (c) Ways to enhance the quality, utility, and clarity of the 
information to be collected; and
    (d) Ways to minimize the burden of the collection of information on 
those

[[Page 52242]]

who are to respond, including the use of appropriate automated, 
electronic, mechanical, or other technological collection techniques.
    Those desiring to comment on these information collections should 
send comments directly to the Office of Management and Budget, Office 
of Information and Regulatory Affairs, Attn: Desk Officer for the 
Department of Transportation, 725 17th Street NW, Washington, DC 20503. 
Comments should be submitted on or prior to October 31, 2019. Comments 
may also be sent via email to the Office of Management and Budget at 
the following address: oira_submissions@omb.eop.gov. OMB is required to 
make a decision concerning the collection of information requirements 
contained in this final rule between 30 and 60 days after publication 
of this document in the Federal Register. Therefore, a comment to OMB 
is best assured of having its full effect if received within 30 days of 
publication.

F. Unfunded Mandates Reform Act of 1995

    An evaluation of Unfunded Mandates Reform Act (UMRA) considerations 
is performed as part of the Final Regulatory Impact Assessment. PHMSA 
determined that this final rule does not impose enforceable duties on 
State, local, or tribal governments or on the private sector of $100 
million or more, adjusted for inflation, in any one year and therefore 
does not have implications under Section 202 of the UMRA of 1995. A 
copy of the RIA is available for review in the docket.

G. National Environmental Policy Act

    PHMSA analyzed this final rule in accordance with the National 
Environmental Policy Act (42 U.S.C. 4332) and determined this action 
will not significantly affect the quality of the human environment. The 
Environmental Assessment for this final rule is in the docket.

H. Executive Order 13132: Federalism

    PHMSA analyzed this final rule in accordance with Executive Order 
13132 (``Federalism''). The final rule does not have a substantial 
direct effect on the States, the relationship between the national 
government and the States, or the distribution of power and 
responsibilities among the various levels of government. This 
rulemaking action does not impose substantial direct compliance costs 
on State and local governments. The pipeline safety laws, specifically 
49 U.S.C. 60104(c), prohibits State safety regulation of interstate 
pipelines. Under the pipeline safety law, States have the ability to 
augment pipeline safety requirements for intrastate pipelines regulated 
by PHMSA, but may not approve safety requirements less stringent than 
those required by Federal law. A State may also regulate an intrastate 
pipeline facility PHMSA does not regulate. It is these statutory 
provisions, not the rule, that govern preemption of State law. 
Therefore, the consultation and funding requirements of Executive Order 
13132 do not apply.

I. Executive Order 13211

    This final rule is not a ``significant energy action'' under 
Executive Order 13211 (Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use). It is not 
likely to have a significant adverse effect on supply, distribution, or 
energy use. Further, the Office of Information and Regulatory Affairs 
has not designated this final rule as a significant energy action.

J. Privacy Act Statement

    Anyone may search the electronic form of all comments received for 
any of our dockets. You may review DOT's complete Privacy Act 
Statement, published on April 11, 2000 (65 FR 19476), in the Federal 
Register at: https://www.govinfo.gov/content/FR-2000-04-11/pdf/00-8505.pdf.

K. Regulation Identifier Number (RIN)

    A regulation identifier number (RIN) is assigned to each regulatory 
action listed in the Unified Agenda of Federal Regulations. The 
Regulatory Information Service Center publishes the Unified Agenda in 
April and October of each year. The RIN number contained in the heading 
of this document can be used to cross-reference this action with the 
Unified Agenda.

List of Subjects

49 CFR Part 191

    MAOP exceedance, Pipeline reporting requirements.

49 CFR Part 192

    Incorporation by reference, Integrity assessments, Material 
properties verification, MAOP reconfirmation, Pipeline safety, 
Predicted failure pressure, Recordkeeping, Risk assessment, Safety 
devices.

    In consideration of the foregoing, PHMSA is amending 49 CFR parts 
191 and 192 as follows:

PART 191--TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE; 
ANNUAL, INCIDENT, AND OTHER REPORTING

0
1. The authority citation for part 191 is revised to read as follows:

    Authority:  30 U.S.C. 185(w)(3), 49 U.S.C. 5121, 60101 et. seq., 
and 49 CFR 1.97.

0
2. In Sec.  191.23, paragraph (a)(6) is revised, paragraph (a)(10) is 
added, and paragraph (b)(4) is revised to read as follows:

Sec.  191.23  Reporting safety-related conditions.

    (a) * * *
    (6) Any malfunction or operating error that causes the pressure--
plus the margin (build-up) allowed for operation of pressure limiting 
or control devices--to exceed either the maximum allowable operating 
pressure of a distribution or gathering line, the maximum well 
allowable operating pressure of an underground natural gas storage 
facility, or the maximum allowable working pressure of an LNG facility 
that contains or processes gas or LNG.
* * * * *
    (10) For transmission pipelines only, each exceedance of the 
maximum allowable operating pressure that exceeds the margin (build-up) 
allowed for operation of pressure-limiting or control devices as 
specified in the applicable requirements of Sec. Sec.  192.201, 
192.620(e), and 192.739. The reporting requirement of this paragraph 
(a)(10) is not applicable to gathering lines, distribution lines, LNG 
facilities, or underground natural gas storage facilities (See 
paragraph (a)(6) of this section).
    (b) * * *
    (4) Is corrected by repair or replacement in accordance with 
applicable safety standards before the deadline for filing the safety-
related condition report. Notwithstanding this exception, a report must 
be filed for:
    (i) Conditions under paragraph (a)(1) of this section, unless the 
condition is localized corrosion pitting on an effectively coated and 
cathodically protected pipeline; and
    (ii) Any condition under paragraph (a)(10) of this section.
* * * * *

0
3. Section 191.25 is revised to read as follows:

Sec.  191.25  Filing safety-related condition reports.

    (a) Each report of a safety-related condition under Sec.  
191.23(a)(1) through (9) must be filed (received by the Associate 
Administrator) in writing

[[Page 52243]]

within 5 working days (not including Saturday, Sunday, or Federal 
holidays) after the day a representative of an operator first 
determines that the condition exists, but not later than 10 working 
days after the day a representative of an operator discovers the 
condition. Separate conditions may be described in a single report if 
they are closely related. Reporting methods and report requirements are 
described in paragraph (c) of this section.
    (b) Each report of a maximum allowable operating pressure 
exceedance meeting the requirements of criteria in Sec.  191.23(a)(10) 
for a gas transmission pipeline must be filed (received by the 
Associate Administrator) in writing within 5 calendar days of the 
exceedance using the reporting methods and report requirements 
described in paragraph (c) of this section.
    (c) Reports must be filed by email to 
InformationResourcesManager@dot.gov or by facsimile to (202) 366-7128. 
For a report made pursuant to Sec.  191.23(a)(1) through (9), the 
report must be headed ``Safety-Related Condition Report.'' For a report 
made pursuant to Sec.  191.23(a)(10), the report must be headed 
``Maximum Allowable Operating Pressure Exceedances.'' All reports must 
provide the following information:
    (1) Name, principal address, and operator identification number 
(OPID) of the operator.
    (2) Date of report.
    (3) Name, job title, and business telephone number of person 
submitting the report.
    (4) Name, job title, and business telephone number of person who 
determined that the condition exists.
    (5) Date condition was discovered and date condition was first 
determined to exist.
    (6) Location of condition, with reference to the State (and town, 
city, or county) or offshore site, and as appropriate, nearest street 
address, offshore platform, survey station number, milepost, landmark, 
or name of pipeline.
    (7) Description of the condition, including circumstances leading 
to its discovery, any significant effects of the condition on safety, 
and the name of the commodity transported or stored.
    (8) The corrective action taken (including reduction of pressure or 
shutdown) before the report is submitted and the planned follow-up or 
future corrective action, including the anticipated schedule for 
starting and concluding such action.

PART 192--TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE: 
MINIMUM FEDERAL SAFETY STANDARDS

0
4. The authority citation for part 192 is revised to read as follows:

    Authority:  30 U.S.C. 185(w)(3), 49 U.S.C. 5103, 60101 et. seq., 
and 49 CFR 1.97.

0
5. In Sec.  192.3, the definitions for ``Engineering critical 
assessment (ECA)'' and ``Moderate consequence area'' are added in 
alphabetical order to read as follows:

Sec.  192.3  Definitions.

* * * * *
    Engineering critical assessment (ECA) means a documented analytical 
procedure based on fracture mechanics principles, relevant material 
properties (mechanical and fracture resistance properties), operating 
history, operational environment, in-service degradation, possible 
failure mechanisms, initial and final defect sizes, and usage of future 
operating and maintenance procedures to determine the maximum tolerable 
sizes for imperfections based upon the pipeline segment maximum 
allowable operating pressure.
* * * * *
    Moderate consequence area means:
    (1) An onshore area that is within a potential impact circle, as 
defined in Sec.  192.903, containing either:
    (i) Five or more buildings intended for human occupancy; or
    (ii) 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 (see: https://www.fhwa.dot.gov/planning/processes/statewide/related/highway_functional_classifications/fcauab.pdf), and that does not meet 
the definition of high consequence area, as defined in Sec.  192.903.
    (2) The length of the moderate consequence area extends axially 
along the length of the pipeline from the outermost edge of the first 
potential impact circle containing either 5 or more buildings intended 
for human occupancy; or any portion of the paved surface, including 
shoulders, of any designated interstate, freeway, or expressway, as 
well as any other principal arterial roadway with 4 or more lanes, to 
the outermost edge of the last contiguous potential impact circle that 
contains either 5 or more buildings intended for human occupancy, or 
any portion of the paved surface, including shoulders, of any 
designated interstate, freeway, or expressway, as well as any other 
principal arterial roadway with 4 or more lanes.
* * * * *

0
6. In Sec.  192.5, paragraph (d) is added to read as follows:

Sec.  192.5  Class locations.

* * * * *
    (d) An operator must have records that document the current class 
location of each pipeline segment and that demonstrate how the operator 
determined each current class location in accordance with this section.

0
7. Amend Sec.  192.7 as follows:
0
a. Revise paragraph (a)(1)(ii);
0
b. Add paragraph (b)(12);
0
c. Revise paragraphs (c)(2) and (4);
0
d. Re-designate paragraphs (d) through (j) as paragraphs (e) through 
(k), respectively;
0
e. Add new paragraphs (d) and (h)(2); and
0
f. Revise newly redesignated paragraph (j)(1).
    The revisions and additions read as follows:

Sec.  192.7  What documents are incorporated by reference partly or 
wholly in this part?

    (a) * * *
    (1) * * *
    (ii) The National Archives and Records Administration (NARA). For 
information on the availability of this material at NARA, email 
fedreg.legal@nara.gov or go to www.archives.gov/federal-register/cfr/ibr-locations.html.
    (b) * * *
    (12) API STANDARD 1163, ``In-Line Inspection Systems 
Qualification,'' Second edition, April 2013, Reaffirmed August 2018, 
(API STD 1163), IBR approved for Sec.  192.493.
    (c) * * *
    (2) ASME/ANSI B16.5-2003, ``Pipe Flanges and Flanged Fittings,'' 
October 2004, (ASME/ANSI B16.5), IBR approved for Sec. Sec.  
192.147(a), 192.279, and 192.607(f).
* * * * *
    (4) ASME/ANSI B31G-1991 (Reaffirmed 2004), ``Manual for Determining 
the Remaining Strength of Corroded Pipelines,'' 2004, (ASME/ANSI B31G), 
IBR approved for Sec. Sec.  192.485(c), 192.632(a), 192.712(b), and 
192.933(a).
* * * * *
    (d) American Society for Nondestructive Testing (ASNT), P.O. Box 
28518, 1711 Arlingate Lane, Columbus, OH 43228, phone: 800-222-2768, 
website: https://www.asnt.org/.

[[Page 52244]]

    (1) ANSI/ASNT ILI-PQ-2005(2010), ``In-line Inspection Personnel 
Qualification and Certification,'' Reapproved October 11, 2010, (ANSI/
ASNT ILI-PQ), IBR approved for Sec.  192.493.
    (2) [Reserved]
* * * * *
    (h) * * *
    (2) NACE Standard Practice 0102-2010, ``In-Line Inspection of 
Pipelines,'' Revised 2010-03-13, (NACE SP0102), IBR approved for 
Sec. Sec.  192.150(a) and 192.493.
* * * * *
    (j) * * *
    (1) AGA, Pipeline Research Committee Project, PR-3-805, ``A 
Modified Criterion for Evaluating the Remaining Strength of Corroded 
Pipe,'' (December 22, 1989), (PRCI PR-3-805 (R-STRENG)), IBR approved 
for Sec. Sec.  192.485(c); 192.632(a); 192.712(b); 192.933(a) and (d).
* * * * *

0
8. In Sec.  192.9, paragraphs (b), (c), and (d)(1), (2), and (6) are 
revised to read as follows:

Sec.  192.9  What requirements apply to gathering lines?

* * * * *
    (b) Offshore lines. An operator of an offshore gathering line must 
comply with requirements of this part applicable to transmission lines, 
except the requirements in Sec. Sec.  192.150, 192.285(e), 192.493, 
192.506, 192.607, 192.619(e), 192.624, 192.710, 192.712, and in subpart 
O of this part.
    (c) Type A lines. An operator of a Type A regulated onshore 
gathering line must comply with the requirements of this part 
applicable to transmission lines, except the requirements in Sec. Sec.  
192.150, 192.285(e), 192.493, 192.506, 192.607, 192.619(e), 192.624, 
192.710, 192.712, and in subpart O of this part. However, operators of 
Type A regulated onshore gathering lines in a Class 2 location may 
demonstrate compliance with subpart N by describing the processes it 
uses to determine the qualification of persons performing operations 
and maintenance tasks.
    (d) * * *
    (1) If a line is new, replaced, relocated, or otherwise changed, 
the design, installation, construction, initial inspection, and initial 
testing must be in accordance with requirements of this part applicable 
to transmission lines except the requirements in Sec. Sec.  192.67, 
192.127, 192.205, 192.227(c), 192.285(e), and 192.506;
    (2) If the pipeline is metallic, control corrosion according to 
requirements of subpart I of this part applicable to transmission lines 
except the requirements in Sec.  192.493;
* * * * *
    (6) Establish the MAOP of the line under Sec.  192.619(a), (b), and 
(c);
* * * * *

0
9. Section 192.18 is added to read as follows:

Sec.  192.18  How to notify PHMSA.

    (a) An operator must provide any notification required by this part 
by--
    (1) Sending the notification by electronic mail to 
InformationResourcesManager@dot.gov; or
    (2) Sending the notification by mail to ATTN: Information Resources 
Manager, DOT/PHMSA/OPS, East Building, 2nd Floor, E22-321, 1200 New 
Jersey Ave. SE, Washington, DC 20590.
    (b) An operator must also notify the appropriate State or local 
pipeline safety authority when an applicable pipeline segment is 
located in a State where OPS has an interstate agent agreement, or an 
intrastate applicable pipeline segment is regulated by that State.
    (c) Unless otherwise specified, if the notification is made 
pursuant to Sec.  192.506(b), Sec.  192.607(e)(4), Sec.  192.607(e)(5), 
Sec.  192.624(c)(2)(iii), Sec.  192.624(c)(6), Sec.  192.632(b)(3), 
Sec.  192.710(c)(7), Sec.  192.712(d)(3)(iv), Sec.  
192.712(e)(2)(i)(E), Sec.  192.921(a)(7), or Sec.  192.937(c)(7) to use 
a different integrity assessment method, analytical method, sampling 
approach, or technique (i.e., ``other technology'') that differs from 
that prescribed in those sections, the operator must notify PHMSA at 
least 90 days in advance of using the other technology. An operator may 
proceed to use the other technology 91 days after submittal of the 
notification unless it receives a letter from the Associate 
Administrator for Pipeline Safety informing the operator that PHMSA 
objects to the proposed use of other technology or that PHMSA requires 
additional time to conduct its review.

Sec.  192.67  [Redesignated as Sec.  192.69]

0
10. Redesignate Sec.  192.67 as Sec.  192.69.
0
11. Section 192.67 is added to read as follows:

Sec.  192.67  Records: Material properties.

    (a) For steel transmission pipelines installed after [July 1, 2020, 
an operator must collect or make, and retain for the life of the 
pipeline, records that document the physical characteristics of the 
pipeline, including diameter, yield strength, ultimate tensile 
strength, wall thickness, seam type, and chemical composition of 
materials for pipe in accordance with Sec. Sec.  192.53 and 192.55. 
Records must include tests, inspections, and attributes required by the 
manufacturing specifications applicable at the time the pipe was 
manufactured or installed.
    (b) For steel transmission pipelines installed on or before July 1, 
2020], if operators have records that document tests, inspections, and 
attributes required by the manufacturing specifications applicable at 
the time the pipe was manufactured or installed, including diameter, 
yield strength, ultimate tensile strength, wall thickness, seam type, 
and chemical composition in accordance with Sec. Sec.  192.53 and 
192.55, operators must retain such records for the life of the 
pipeline.
    (c) For steel transmission pipeline segments installed on or before 
July 1, 2020], if an operator does not have records necessary to 
establish the MAOP of a pipeline segment, the operator may be subject 
to the requirements of Sec.  192.624 according to the terms of that 
section.

0
12. Section 192.127 is added to read as follows:

Sec.  192.127  Records: Pipe design.

    (a) For steel transmission pipelines installed after July 1, 2020], 
an operator must collect or make, and retain for the life of the 
pipeline, records documenting that the pipe is designed to withstand 
anticipated external pressures and loads in accordance with Sec.  
192.103 and documenting that the determination of design pressure for 
the pipe is made in accordance with Sec.  192.105.
    (b) For steel transmission pipelines installed on or before July 1, 
2020, if operators have records documenting pipe design and the 
determination of design pressure in accordance with Sec. Sec.  192.103 
and 192.105, operators must retain such records for the life of the 
pipeline.
    (c) For steel transmission pipeline segments installed on or before 
July 1, 2020, if an operator does not have records necessary to 
establish the MAOP of a pipeline segment, the operator may be subject 
to the requirements of Sec.  192.624 according to the terms of that 
section.

0
13. In Sec.  192.150, paragraph (a) is revised to read as follows:

Sec.  192.150  Passage of internal inspection devices.

    (a) Except as provided in paragraphs (b) and (c) of this section, 
each new transmission line and each replacement of line pipe, valve, 
fitting, or other line component in a transmission line, must

[[Page 52245]]

be designed and constructed to accommodate the passage of instrumented 
internal inspection devices in accordance with NACE SP0102, section 7 
(incorporated by reference, see Sec.  192.7).
* * * * *

0
14. Section 192.205 is added to read as follows:

Sec.  192.205  Records: Pipeline components.

    (a) For steel transmission pipelines installed after July 1, 2020, 
an operator must collect or make, and retain for the life of the 
pipeline, records documenting the manufacturing standard and pressure 
rating to which each valve was manufactured and tested in accordance 
with this subpart. Flanges, fittings, branch connections, extruded 
outlets, anchor forgings, and other components with material yield 
strength grades of 42,000 psi (X42) or greater and with nominal 
diameters of greater than 2 inches must have records documenting the 
manufacturing specification in effect at the time of manufacture, 
including yield strength, ultimate tensile strength, and chemical 
composition of materials.
    (b) For steel transmission pipelines installed on or before July 1, 
2020, if operators have records documenting the manufacturing standard 
and pressure rating for valves, flanges, fittings, branch connections, 
extruded outlets, anchor forgings, and other components with material 
yield strength grades of 42,000 psi (X42) or greater and with nominal 
diameters of greater than 2 inches, operators must retain such records 
for the life of the pipeline.
    (c) For steel transmission pipeline segments installed on or before 
July 1, 2020, if an operator does not have records necessary to 
establish the MAOP of a pipeline segment, the operator may be subject 
to the requirements of Sec.  192.624 according to the terms of that 
section.

0
15. In Sec.  192.227, paragraph (c) is added to read as follows:

Sec.  192.227  Qualification of welders.

* * * * *
    (c) For steel transmission pipe installed after July 1, 2021, 
records demonstrating each individual welder qualification at the time 
of construction in accordance with this section must be retained for a 
minimum of 5 years following construction.

0
16. In Sec.  192.285, paragraph (e) is added to read as follows:

Sec.  192.285  Plastic pipe: Qualifying persons to make joints.

* * * * *
    (e) For transmission pipe installed after July 1, 2021, records 
demonstrating each person's plastic pipe joining qualifications at the 
time of construction in accordance with this section must be retained 
for a minimum of 5 years following construction.

0
17. Section 192.493 is added to read as follows:

Sec.  192.493   In-line inspection of pipelines.

    When conducting in-line inspections of pipelines required by this 
part, an operator must comply with API STD 1163, ANSI/ASNT ILI-PQ, and 
NACE SP0102, (incorporated by reference, see Sec.  192.7). Assessments 
may be conducted using tethered or remotely controlled tools, not 
explicitly discussed in NACE SP0102, provided they comply with those 
sections of NACE SP0102 that are applicable.

0
18. Section 192.506 is added to read as follows:

Sec.  192.506  Transmission lines: Spike hydrostatic pressure test.

    (a) Spike test requirements. Whenever a segment of steel 
transmission pipeline that is operated at a hoop stress level of 30 
percent or more of SMYS is spike tested under this part, the spike 
hydrostatic pressure test must be conducted in accordance with this 
section.
    (1) The test must use water as the test medium.
    (2) The baseline test pressure must be as specified in the 
applicable paragraphs of Sec.  192.619(a)(2) or Sec.  192.620(a)(2), 
whichever applies.
    (3) The test must be conducted by maintaining a pressure at or 
above the baseline test pressure for at least 8 hours as specified in 
Sec.  192.505.
    (4) After the test pressure stabilizes at the baseline pressure and 
within the first 2 hours of the 8-hour test interval, the hydrostatic 
pressure must be raised (spiked) to a minimum of the lesser of 1.5 
times MAOP or 100% SMYS. This spike hydrostatic pressure test must be 
held for at least 15 minutes after the spike test pressure stabilizes.
    (b) Other technology or other technical evaluation process. 
Operators may use other technology or another process supported by a 
documented engineering analysis for establishing a spike hydrostatic 
pressure test or equivalent. Operators must notify PHMSA 90 days in 
advance of the assessment or reassessment requirements of this 
subchapter. The notification must be made in accordance with Sec.  
192.18 and must include the following information:
    (1) Descriptions of the technology or technologies to be used for 
all tests, examinations, and assessments;
    (2) Procedures and processes to conduct tests, examinations, 
assessments, perform evaluations, analyze defects, and remediate 
defects discovered;
    (3) Data requirements, including original design, maintenance and 
operating history, anomaly or flaw characterization;
    (4) Assessment techniques and acceptance criteria;
    (5) Remediation methods for assessment findings;
    (6) Spike hydrostatic pressure test monitoring and acceptance 
procedures, if used;
    (7) Procedures for remaining crack growth analysis and pipeline 
segment life analysis for the time interval for additional assessments, 
as required; and
    (8) Evidence of a review of all procedures and assessments by a 
qualified technical subject matter expert.

0
19. In Sec.  192.517, paragraph (a) introductory text is revised to 
read as follows:

Sec.  192.517   Records: Tests.

    (a) An operator must make, and retain for the useful life of the 
pipeline, a record of each test performed under Sec. Sec.  192.505, 
192.506, and 192.507. The record must contain at least the following 
information:
* * * * *

0
20. Section 192.607 is added to read as follows:

Sec.  192.607  Verification of Pipeline Material Properties and 
Attributes: Onshore steel transmission pipelines.

    (a) Applicability. Wherever required by this part, operators of 
onshore steel transmission pipelines must document and verify material 
properties and attributes in accordance with this section.
    (b) Documentation of material properties and attributes. Records 
established under this section documenting physical pipeline 
characteristics and attributes, including diameter, wall thickness, 
seam type, and grade (e.g., yield strength, ultimate tensile strength, 
or pressure rating for valves and flanges, etc.), must be maintained 
for the life of the pipeline and be traceable, verifiable, and 
complete. Charpy v-notch toughness values established under this 
section needed to meet the requirements of the ECA method at Sec.  
192.624(c)(3) or the fracture mechanics requirements at Sec.  192.712 
must be maintained for the life of the pipeline.

[[Page 52246]]

    (c) Verification of material properties and attributes. If an 
operator does not have traceable, verifiable, and complete records 
required by paragraph (b) of this section, the operator must develop 
and implement procedures for conducting nondestructive or destructive 
tests, examinations, and assessments in order to verify the material 
properties of aboveground line pipe and components, and of buried line 
pipe and components when excavations occur at the following 
opportunities: Anomaly direct examinations, in situ evaluations, 
repairs, remediations, maintenance, and excavations that are associated 
with replacements or relocations of pipeline segments that are removed 
from service. The procedures must also provide for the following:
    (1) For nondestructive tests, at each test location, material 
properties for minimum yield strength and ultimate tensile strength 
must be determined at a minimum of 5 places in at least 2 
circumferential quadrants of the pipe for a minimum total of 10 test 
readings at each pipe cylinder location.
    (2) For destructive tests, at each test location, a set of material 
properties tests for minimum yield strength and ultimate tensile 
strength must be conducted on each test pipe cylinder removed from each 
location, in accordance with API Specification 5L.
    (3) Tests, examinations, and assessments must be appropriate for 
verifying the necessary material properties and attributes.
    (4) If toughness properties are not documented, the procedures must 
include accepted industry methods for verifying pipe material 
toughness.
    (5) Verification of material properties and attributes for non-line 
pipe components must comply with paragraph (f) of this section.
    (d) Special requirements for nondestructive Methods. Procedures 
developed in accordance with paragraph (c) of this section for 
verification of material properties and attributes using nondestructive 
methods must:
    (1) Use methods, tools, procedures, and techniques that have been 
validated by a subject matter expert based on comparison with 
destructive test results on material of comparable grade and vintage;
    (2) Conservatively account for measurement inaccuracy and 
uncertainty using reliable engineering tests and analyses; and
    (3) Use test equipment that has been properly calibrated for 
comparable test materials prior to usage.
    (e) Sampling multiple segments of pipe. To verify material 
properties and attributes for a population of multiple, comparable 
segments of pipe without traceable, verifiable, and complete records, 
an operator may use a sampling program in accordance with the following 
requirements:
    (1) The operator must define separate populations of similar 
segments of pipe for each combination of the following material 
properties and attributes: Nominal wall thicknesses, grade, 
manufacturing process, pipe manufacturing dates, and construction 
dates. If the dates between the manufacture or construction of the 
pipeline segments exceeds 2 years, those segments cannot be considered 
as the same vintage for the purpose of defining a population under this 
section. The total population mileage is the cumulative mileage of 
pipeline segments in the population. The pipeline segments need not be 
continuous.
    (2) For each population defined according to paragraph (e)(1) of 
this section, the operator must determine material properties at all 
excavations that expose the pipe associated with anomaly direct 
examinations, in situ evaluations, repairs, remediations, or 
maintenance, except for pipeline segments exposed during excavation 
activities pursuant to Sec.  192.614, until completion of the lesser of 
the following:
    (i) One excavation per mile rounded up to the nearest whole number; 
or
    (ii) 150 excavations if the population is more than 150 miles.
    (3) Prior tests conducted for a single excavation according to the 
requirements of paragraph (c) of this section may be counted as one 
sample under the sampling requirements of this paragraph (e).
    (4) If the test results identify line pipe with properties that are 
not consistent with available information or existing expectations or 
assumed properties used for operations and maintenance in the past, the 
operator must establish an expanded sampling program. The expanded 
sampling program must use valid statistical bases designed to achieve 
at least a 95% confidence level that material properties used in the 
operation and maintenance of the pipeline are valid. The approach must 
address how the sampling plan will be expanded to address findings that 
reveal material properties that are not consistent with all available 
information or existing expectations or assumed material properties 
used for pipeline operations and maintenance in the past. Operators 
must notify PHMSA in advance of using an expanded sampling approach in 
accordance with Sec.  192.18.
    (5) An operator may use an alternative statistical sampling 
approach that differs from the requirements specified in paragraph 
(e)(2) of this section. The alternative sampling program must use valid 
statistical bases designed to achieve at least a 95% confidence level 
that material properties used in the operation and maintenance of the 
pipeline are valid. The approach must address how the sampling plan 
will be expanded to address findings that reveal material properties 
that are not consistent with all available information or existing 
expectations or assumed material properties used for pipeline 
operations and maintenance in the past. Operators must notify PHMSA in 
advance of using an alternative sampling approach in accordance with 
Sec.  192.18.
    (f) Components. For mainline pipeline components other than line 
pipe, an operator must develop and implement procedures in accordance 
with paragraph (c) of this section for establishing and documenting the 
ANSI rating or pressure rating (in accordance with ASME/ANSI B16.5 
(incorporated by reference, see Sec.  192.7)),
    (1) Operators are not required to test for the chemical and 
mechanical properties of components in compressor stations, meter 
stations, regulator stations, separators, river crossing headers, 
mainline valve assemblies, valve operator piping, or cross-connections 
with isolation valves from the mainline pipeline.
    (2) Verification of material properties is required for non-line 
pipe components, including valves, flanges, fittings, fabricated 
assemblies, and other pressure retaining components and appurtenances 
that are:
    (i) Larger than 2 inches in nominal outside diameter,
    (ii) Material grades of 42,000 psi (Grade X-42) or greater, or
    (iii) Appurtenances of any size that are directly installed on the 
pipeline and cannot be isolated from mainline pipeline pressures.
    (3) Procedures for establishing material properties of non-line 
pipe components must be based on the documented manufacturing 
specification for the components. If specifications are not known, 
usage of manufacturer's stamped, marked, or tagged material pressure 
ratings and material type may be used to establish pressure rating. 
Operators must document the method used to determine the pressure 
rating and the findings of that determination.
    (g) Uprating. The material properties determined from the 
destructive or nondestructive tests required by this

[[Page 52247]]

section cannot be used to raise the grade or specification of the 
material, unless the original grade or specification is unknown and 
MAOP is based on an assumed yield strength of 24,000 psi in accordance 
with Sec.  192.107(b)(2).

0
21. In Sec.  192.619, the introductory text of paragraphs (a) 
introductory text and (a)(2) and (4) are revised and paragraphs (e) and 
(f) are added to read as follows:

Sec.  192.619   Maximum allowable operating pressure: Steel or plastic 
pipelines.

    (a) No person may operate a segment of steel or plastic pipeline at 
a pressure that exceeds a maximum allowable operating pressure (MAOP) 
determined under paragraph (c), (d), or (e) of this section, or the 
lowest of the following:
* * * * *
    (2) The pressure obtained by dividing the pressure to which the 
pipeline segment was tested after construction as follows:
    (i) For plastic pipe in all locations, the test pressure is divided 
by a factor of 1.5.
    (ii) For steel pipe operated at 100 psi (689 kPa) gage or more, the 
test pressure is divided by a factor determined in accordance with the 
Table 1 to paragraph (a)(2)(ii):

                                         Table 1 to Paragraph (a)(2)(ii)
----------------------------------------------------------------------------------------------------------------
                                                                          Factors,\1\ segment--
                                                        --------------------------------------------------------
                                       Installed before   Installed after
           Class location              (Nov. 12, 1970)    (Nov. 11, 1970)    Installed on or    Converted under
                                                          and before July     after July 1,      Sec.   192.14
                                                              1, 2020              2020
----------------------------------------------------------------------------------------------------------------
1...................................                1.1                1.1               1.25               1.25
2...................................               1.25               1.25               1.25               1.25
3...................................                1.4                1.5                1.5                1.5
4...................................                1.4                1.5                1.5                1.5
----------------------------------------------------------------------------------------------------------------
\1\ For offshore pipeline segments installed, uprated or converted after July 31, 1977, that are not located on
  an offshore platform, the factor is 1.25. For pipeline segments installed, uprated or converted after July 31,
  1977, that are located on an offshore platform or on a platform in inland navigable waters, including a pipe
  riser, the factor is 1.5.

* * * * *
    (4) The pressure determined by the operator to be the maximum safe 
pressure after considering and accounting for records of material 
properties, including material properties verified in accordance with 
Sec.  192.607, if applicable, and the history of the pipeline segment, 
including known corrosion and actual operating pressure.
* * * * *
    (e) Notwithstanding the requirements in paragraphs (a) through (d) 
of this section, operators of onshore steel transmission pipelines that 
meet the criteria specified in Sec.  192.624(a) must establish and 
document the maximum allowable operating pressure in accordance with 
Sec.  192.624.
    (f) Operators of onshore steel transmission pipelines must make and 
retain records necessary to establish and document the MAOP of each 
pipeline segment in accordance with paragraphs (a) through (e) of this 
section as follows:
    (1) Operators of pipelines in operation as of [July 1, 2020 must 
retain any existing records establishing MAOP for the life of the 
pipeline;
    (2) Operators of pipelines in operation as of July 1, 2020 that do 
not have records establishing MAOP and are required to reconfirm MAOP 
in accordance with Sec.  192.624, must retain the records reconfirming 
MAOP for the life of the pipeline; and
    (3) Operators of pipelines placed in operation after July 1, 2020 
must make and retain records establishing MAOP for the life of the 
pipeline.

0
22. Section 192.624 is added to read as follows:

Sec.  192.624  Maximum allowable operating pressure reconfirmation: 
Onshore steel transmission pipelines.

    (a) Applicability. Operators of onshore steel transmission pipeline 
segments must reconfirm the maximum allowable operating pressure (MAOP) 
of all pipeline segments in accordance with the requirements of this 
section if either of the following conditions are met:
    (1) Records necessary to establish the MAOP in accordance with 
Sec.  192.619(a), including records required by Sec.  192.517(a), are 
not traceable, verifiable, and complete and the pipeline is located in 
one of the following locations:
    (i) A high consequence area as defined in Sec.  192.903; or
    (ii) A Class 3 or Class 4 location.
    (2) The pipeline segment's MAOP was established in accordance with 
Sec.  192.619(c), the pipeline segment's MAOP is greater than or equal 
to 30 percent of the specified minimum yield strength, and the pipeline 
segment is located in one of the following areas:
    (i) A high consequence area as defined in Sec.  192.903;
    (ii) A Class 3 or Class 4 location; or
    (iii) A moderate consequence area as defined in Sec.  192.3, if the 
pipeline segment can accommodate inspection by means of instrumented 
inline inspection tools.
    (b) Procedures and completion dates. Operators of a pipeline 
subject to this section must develop and document procedures for 
completing all actions required by this section by July 1, 2021. These 
procedures must include a process for reconfirming MAOP for any 
pipelines that meet a condition of Sec.  192.624(a), and for performing 
a spike test or material verification in accordance with Sec. Sec.  
192.506 and 192.607, if applicable. All actions required by this 
section must be completed according to the following schedule:
    (1) Operators must complete all actions required by this section on 
at least 50% of the pipeline mileage by July 3, 2028.
    (2) Operators must complete all actions required by this section on 
100% of the pipeline mileage by July 2, 2035 or as soon as practicable, 
but not to exceed 4 years after the pipeline segment first meets a 
condition of Sec.  192.624(a) (e.g., due to a location becoming a high 
consequence area), whichever is later.
    (3) If operational and environmental constraints limit an operator 
from meeting the deadlines in Sec.  192.624, the operator may petition 
for an extension of the completion deadlines by up to 1 year, upon 
submittal of a notification in accordance with Sec.  192.18. The 
notification must include an up-to-date plan for completing all actions 
in accordance with this section, the reason for the requested 
extension, current status, proposed completion date, outstanding 
remediation activities, and

[[Page 52248]]

any needed temporary measures needed to mitigate the impact on safety.
    (c) Maximum allowable operating pressure determination. Operators 
of a pipeline segment meeting a condition in paragraph (a) of this 
section must reconfirm its MAOP using one of the following methods:
    (1) Method 1: Pressure test. Perform a pressure test and verify 
material properties records in accordance with Sec.  192.607 and the 
following requirements:
    (i) Pressure test. Perform a pressure test in accordance with 
subpart J of this part. The MAOP must be equal to the test pressure 
divided by the greater of either 1.25 or the applicable class location 
factor in Sec.  192.619(a)(2)(ii).
    (ii) Material properties records. Determine if the following 
material properties records are documented in traceable, verifiable, 
and complete records: Diameter, wall thickness, seam type, and grade 
(minimum yield strength, ultimate tensile strength).
    (iii) Material properties verification. If any of the records 
required by paragraph (c)(1)(ii) of this section are not documented in 
traceable, verifiable, and complete records, the operator must obtain 
the missing records in accordance with Sec.  192.607. An operator must 
test the pipe materials cut out from the test manifold sites at the 
time the pressure test is conducted. If there is a failure during the 
pressure test, the operator must test any removed pipe from the 
pressure test failure in accordance with Sec.  192.607.
    (2) Method 2: Pressure Reduction. Reduce pressure, as necessary, 
and limit MAOP to no greater than the highest actual operating pressure 
sustained by the pipeline during the 5 years preceding October 1, 2019, 
divided by the greater of 1.25 or the applicable class location factor 
in Sec.  192.619(a)(2)(ii). The highest actual sustained pressure must 
have been reached for a minimum cumulative duration of 8 hours during a 
continuous 30-day period. The value used as the highest actual 
sustained operating pressure must account for differences between 
upstream and downstream pressure on the pipeline by use of either the 
lowest maximum pressure value for the entire pipeline segment or using 
the operating pressure gradient along the entire pipeline segment 
(i.e., the location-specific operating pressure at each location).
    (i) Where the pipeline segment has had a class location change in 
accordance with Sec.  192.611, and records documenting diameter, wall 
thickness, seam type, grade (minimum yield strength and ultimate 
tensile strength), and pressure tests are not documented in traceable, 
verifiable, and complete records, the operator must reduce the pipeline 
segment MAOP as follows:
    (A) For pipeline segments where a class location changed from Class 
1 to Class 2, from Class 2 to Class 3, or from Class 3 to Class 4, 
reduce the pipeline MAOP to no greater than the highest actual 
operating pressure sustained by the pipeline during the 5 years 
preceding October 1, 2019, divided by 1.39 for Class 1 to Class 2, 1.67 
for Class 2 to Class 3, and 2.00 for Class 3 to Class 4.
    (B) For pipeline segments where a class location changed from Class 
1 to Class 3, reduce the pipeline MAOP to no greater than the highest 
actual operating pressure sustained by the pipeline during the 5 years 
preceding October 1, 2019, divided by 2.00.
    (ii) Future uprating of the pipeline segment in accordance with 
subpart K is allowed if the MAOP is established using Method 2.
    (iii) If an operator elects to use Method 2, but desires to use a 
less conservative pressure reduction factor or longer look-back period, 
the operator must notify PHMSA in accordance with Sec.  192.18 no later 
than 7 calendar days after establishing the reduced MAOP. The 
notification must include the following details:
    (A) Descriptions of the operational constraints, special 
circumstances, or other factors that preclude, or make it impractical, 
to use the pressure reduction factor specified in Sec.  192.624(c)(2);
    (B) The fracture mechanics modeling for failure stress pressures 
and cyclic fatigue crack growth analysis that complies with Sec.  
192.712;
    (C) Justification that establishing MAOP by another method allowed 
by this section is impractical;
    (D) Justification that the reduced MAOP determined by the operator 
is safe based on analysis of the condition of the pipeline segment, 
including material properties records, material properties verified in 
accordance Sec.  192.607, and the history of the pipeline segment, 
particularly known corrosion and leakage, and the actual operating 
pressure, and additional compensatory preventive and mitigative 
measures taken or planned; and
    (E) Planned duration for operating at the requested MAOP, long-term 
remediation measures and justification of this operating time interval, 
including fracture mechanics modeling for failure stress pressures and 
cyclic fatigue growth analysis and other validated forms of engineering 
analysis that have been reviewed and confirmed by subject matter 
experts.
    (3) Method 3: Engineering Critical Assessment (ECA). Conduct an ECA 
in accordance with Sec.  192.632.
    (4) Method 4: Pipe Replacement. Replace the pipeline segment in 
accordance with this part.
    (5) Method 5: Pressure Reduction for Pipeline Segments with Small 
Potential Impact Radius. Pipelines with a potential impact radius (PIR) 
less than or equal to 150 feet may establish the MAOP as follows:
    (i) Reduce the MAOP to no greater than the highest actual operating 
pressure sustained by the pipeline during 5 years preceding October 1, 
2019, divided by 1.1. The highest actual sustained pressure must have 
been reached for a minimum cumulative duration of 8 hours during one 
continuous 30-day period. The reduced MAOP must account for differences 
between discharge and upstream pressure on the pipeline by use of 
either the lowest value for the entire pipeline segment or the 
operating pressure gradient (i.e., the location specific operating 
pressure at each location);
    (ii) Conduct patrols in accordance with Sec.  192.705 paragraphs 
(a) and (c) and conduct instrumented leakage surveys in accordance with 
Sec.  192.706 at intervals not to exceed those in the following table 1 
to Sec.  192.624(c)(5)(ii):

                   Table 1 to Sec.   192.624(c)(5)(ii)
------------------------------------------------------------------------
       Class locations               Patrols           Leakage surveys
------------------------------------------------------------------------
(A) Class 1 and Class 2.....  3 \1/2\ months, but   3 \1/2\ months, but
                               at least four times   at least four times
                               each calendar year.   each calendar year.
(B) Class 3 and Class 4.....  3 months, but at      3 months, but at
                               least six times       least six times
                               each calendar year.   each calendar year.
------------------------------------------------------------------------

[[Page 52249]]

    (iii) Under Method 5, future uprating of the pipeline segment in 
accordance with subpart K is allowed.
    (6) Method 6: Alternative Technology. Operators may use an 
alternative technical evaluation process that provides a documented 
engineering analysis for establishing MAOP. If an operator elects to 
use alternative technology, the operator must notify PHMSA in advance 
in accordance with Sec.  192.18. The notification must include 
descriptions of the following details:
    (i) The technology or technologies to be used for tests, 
examinations, and assessments; the method for establishing material 
properties; and analytical techniques with similar analysis from prior 
tool runs done to ensure the results are consistent with the required 
corresponding hydrostatic test pressure for the pipeline segment being 
evaluated;
    (ii) Procedures and processes to conduct tests, examinations, 
assessments and evaluations, analyze defects and flaws, and remediate 
defects discovered;
    (iii) Pipeline segment data, including original design, maintenance 
and operating history, anomaly or flaw characterization;
    (iv) Assessment techniques and acceptance criteria, including 
anomaly detection confidence level, probability of detection, and 
uncertainty of the predicted failure pressure quantified as a fraction 
of specified minimum yield strength;
    (v) If any pipeline segment contains cracking or may be susceptible 
to cracking or crack-like defects found through or identified by 
assessments, leaks, failures, manufacturing vintage histories, or any 
other available information about the pipeline, the operator must 
estimate the remaining life of the pipeline in accordance with 
paragraph Sec.  192.712;
    (vi) Operational monitoring procedures;
    (vii) Methodology and criteria used to justify and establish the 
MAOP; and
    (vii) Documentation of the operator's process and procedures used 
to implement the use of the alternative technology, including any 
records generated through its use.
    (d) Records. An operator must retain records of investigations, 
tests, analyses, assessments, repairs, replacements, alterations, and 
other actions taken in accordance with the requirements of this section 
for the life of the pipeline.

0
23. Section 192.632 is added to read as follows:

Sec.  192.632   Engineering Critical Assessment for Maximum Allowable 
Operating Pressure Reconfirmation: Onshore steel transmission 
pipelines.

    When an operator conducts an MAOP reconfirmation in accordance with 
Sec.  192.624(c)(3) ``Method 3'' using an ECA to establish the material 
strength and MAOP of the pipeline segment, the ECA must comply with the 
requirements of this section. The ECA must assess: Threats; loadings 
and operational circumstances relevant to those threats, including 
along the pipeline right-of way; outcomes of the threat assessment; 
relevant mechanical and fracture properties; in-service degradation or 
failure processes; and initial and final defect size relevance. The ECA 
must quantify the interacting effects of threats on any defect in the 
pipeline.
    (a) ECA Analysis. (1) The material properties required to perform 
an ECA analysis in accordance with this paragraph are as follows: 
Diameter, wall thickness, seam type, grade (minimum yield strength and 
ultimate tensile strength), and Charpy v-notch toughness values based 
upon the lowest operational temperatures, if applicable. If any 
material properties required to perform an ECA for any pipeline segment 
in accordance with this paragraph are not documented in traceable, 
verifiable and complete records, an operator must use conservative 
assumptions and include the pipeline segment in its program to verify 
the undocumented information in accordance with Sec.  192.607. The ECA 
must integrate, analyze, and account for the material properties, the 
results of all tests, direct examinations, destructive tests, and 
assessments performed in accordance with this section, along with other 
pertinent information related to pipeline integrity, including close 
interval surveys, coating surveys, interference surveys required by 
subpart I of this part, cause analyses of prior incidents, prior 
pressure test leaks and failures, other leaks, pipe inspections, and 
prior integrity assessments, including those required by Sec. Sec.  
192.617, 192.710, and subpart O of this part.
    (2) The ECA must analyze and determine the predicted failure 
pressure for the defect being assessed using procedures that implement 
the appropriate failure criteria and justification as follows:
    (i) The ECA must analyze any cracks or crack-like defects remaining 
in the pipe, or that could remain in the pipe, to determine the 
predicted failure pressure of each defect in accordance with Sec.  
192.712.
    (ii) The ECA must analyze any metal loss defects not associated 
with a dent, including corrosion, gouges, scrapes or other metal loss 
defects that could remain in the pipe, to determine the predicted 
failure pressure. ASME/ANSI B31G (incorporated by reference, see Sec.  
192.7) or R-STRENG (incorporated by reference, see Sec.  192.7) must be 
used for corrosion defects. Both procedures and their analysis apply to 
corroded regions that do not penetrate the pipe wall over 80 percent of 
the wall thickness and are subject to the limitations prescribed in the 
equations' procedures. The ECA must use conservative assumptions for 
metal loss dimensions (length, width, and depth).
    (iii) When determining the predicted failure pressure for gouges, 
scrapes, selective seam weld corrosion, crack-related defects, or any 
defect within a dent, appropriate failure criteria and justification of 
the criteria must be used and documented.
    (iv) If SMYS or actual material yield and ultimate tensile strength 
is not known or not documented by traceable, verifiable, and complete 
records, then the operator must assume 30,000 p.s.i. or determine the 
material properties using Sec.  192.607.
    (3) The ECA must analyze the interaction of defects to 
conservatively determine the most limiting predicted failure pressure. 
Examples include, but are not limited to, cracks in or near locations 
with corrosion metal loss, dents with gouges or other metal loss, or 
cracks in or near dents or other deformation damage. The ECA must 
document all evaluations and any assumptions used in the ECA process.
    (4) The MAOP must be established at the lowest predicted failure 
pressure for any known or postulated defect, or interacting defects, 
remaining in the pipe divided by the greater of 1.25 or the applicable 
factor listed in Sec.  192.619(a)(2)(ii).
    (b) Assessment to determine defects remaining in the pipe. An 
operator must utilize previous pressure tests or develop and implement 
an assessment program to determine the size of defects remaining in the 
pipe to be analyzed in accordance with paragraph (a) of this section.
    (1) An operator may use a previous pressure test that complied with 
subpart J to determine the defects remaining in the pipe if records for 
a pressure test meeting the requirements of subpart J of this part 
exist for the pipeline segment. The operator must calculate the largest 
defect that could have survived the pressure test. The operator must 
predict how much the defects have grown since the date of the pressure 
test in

[[Page 52250]]

accordance with Sec.  192.712. The ECA must analyze the predicted size 
of the largest defect that could have survived the pressure test that 
could remain in the pipe at the time the ECA is performed. The operator 
must calculate the remaining life of the most severe defects that could 
have survived the pressure test and establish a re-assessment interval 
in accordance with the methodology in Sec.  192.712.
    (2) Operators may use an inline inspection program in accordance 
with paragraph (c) of this section.
    (3) Operators may use ``other technology'' if it is validated by a 
subject matter expert to produce an equivalent understanding of the 
condition of the pipe equal to or greater than pressure testing or an 
inline inspection program. If an operator elects to use ``other 
technology'' in the ECA, it must notify PHMSA in advance of using the 
other technology in accordance with Sec.  192.18. The ``other 
technology'' notification must have:
    (i) Descriptions of the technology or technologies to be used for 
all tests, examinations, and assessments, including characterization of 
defect size used in the crack assessments (length, depth, and 
volumetric); and
    (ii) Procedures and processes to conduct tests, examinations, 
assessments and evaluations, analyze defects, and remediate defects 
discovered.
    (c) In-line inspection. An inline inspection (ILI) program to 
determine the defects remaining the pipe for the ECA analysis must be 
performed using tools that can detect wall loss, deformation from 
dents, wrinkle bends, ovalities, expansion, seam defects, including 
cracking and selective seam weld corrosion, longitudinal, 
circumferential and girth weld cracks, hard spot cracking, and stress 
corrosion cracking.
    (1) If a pipeline has segments that might be susceptible to hard 
spots based on assessment, leak, failure, manufacturing vintage 
history, or other information, then the ILI program must include a tool 
that can detect hard spots.
    (2) If the pipeline has had a reportable incident, as defined in 
Sec.  191.3, attributed to a girth weld failure since its most recent 
pressure test, then the ILI program must include a tool that can detect 
girth weld defects unless the ECA analysis performed in accordance with 
this section includes an engineering evaluation program to analyze and 
account for the susceptibility of girth weld failure due to lateral 
stresses.
    (3) Inline inspection must be performed in accordance with Sec.  
192.493.
    (4) An operator must use unity plots or equivalent methodologies to 
validate the performance of the ILI tools in identifying and sizing 
actionable manufacturing and construction related anomalies. Enough 
data points must be used to validate tool performance at the same or 
better statistical confidence level provided in the tool 
specifications. The operator must have a process for identifying 
defects outside the tool performance specifications and following up 
with the ILI vendor to conduct additional in-field examinations, 
reanalyze ILI data, or both.
    (5) Interpretation and evaluation of assessment results must meet 
the requirements of Sec. Sec.  192.710, 192.713, and subpart O of this 
part, and must conservatively account for the accuracy and reliability 
of ILI, in-the-ditch examination methods and tools, and any other 
assessment and examination results used to determine the actual sizes 
of cracks, metal loss, deformation and other defect dimensions by 
applying the most conservative limit of the tool tolerance 
specification. ILI and in-the-ditch examination tools and procedures 
for crack assessments (length and depth) must have performance and 
evaluation standards confirmed for accuracy through confirmation tests 
for the defect types and pipe material vintage being evaluated. 
Inaccuracies must be accounted for in the procedures for evaluations 
and fracture mechanics models for predicted failure pressure 
determinations.
    (6) Anomalies detected by ILI assessments must be remediated in 
accordance with applicable criteria in Sec. Sec.  192.713 and 192.933.
    (d) Defect remaining life. If any pipeline segment contains 
cracking or may be susceptible to cracking or crack-like defects found 
through or identified by assessments, leaks, failures, manufacturing 
vintage histories, or any other available information about the 
pipeline, the operator must estimate the remaining life of the pipeline 
in accordance with Sec.  192.712.
    (e) Records. An operator must retain records of investigations, 
tests, analyses, assessments, repairs, replacements, alterations, and 
other actions taken in accordance with the requirements of this section 
for the life of the pipeline.

0
24. Section 192.710 is added to read as follows:

Sec.  192.710   Transmission lines: Assessments outside of high 
consequence areas.

    (a) Applicability: This section applies to onshore steel 
transmission pipeline segments with a maximum allowable operating 
pressure of greater than or equal to 30% of the specified minimum yield 
strength and are located in:
    (1) A Class 3 or Class 4 location; or
    (2) A moderate consequence area as defined in Sec.  192.3, if the 
pipeline segment can accommodate inspection by means of an instrumented 
inline inspection tool (i.e., ``smart pig'').
    (3) This section does not apply to a pipeline segment located in a 
high consequence area as defined in Sec.  192.903.
    (b) General--(1) Initial assessment. An operator must perform 
initial assessments in accordance with this section based on a risk-
based prioritization schedule and complete initial assessment for all 
applicable pipeline segments no later than July 3, 2034, or as soon as 
practicable but not to exceed 10 years after the pipeline segment first 
meets the conditions of Sec.  192.710(a) (e.g., due to a change in 
class location or the area becomes a moderate consequence area), 
whichever is later.
    (2) Periodic reassessment. An operator must perform periodic 
reassessments at least once every 10 years, with intervals not to 
exceed 126 months, or a shorter reassessment interval based upon the 
type of anomaly, operational, material, and environmental conditions 
found on the pipeline segment, or as necessary to ensure public safety.
    (3) Prior assessment. An operator may use a prior assessment 
conducted before July 1, 2020 as an initial assessment for the pipeline 
segment, if the assessment met the subpart O requirements of part 192 
for in-line inspection at the time of the assessment. If an operator 
uses this prior assessment as its initial assessment, the operator must 
reassess the pipeline segment according to the reassessment interval 
specified in paragraph (b)(2) of this section calculated from the date 
of the prior assessment.
    (4) MAOP verification. An integrity assessment conducted in 
accordance with the requirements of Sec.  192.624(c) for establishing 
MAOP may be used as an initial assessment or reassessment under this 
section.
    (c) Assessment method. The initial assessments and the 
reassessments required by paragraph (b) of this section must be capable 
of identifying anomalies and defects associated with each of the 
threats to which the pipeline segment is susceptible and must be 
performed using one or more of the following methods:
    (1) Internal inspection. Internal inspection tool or tools capable 
of detecting those threats to which the

[[Page 52251]]

pipeline is susceptible, such as corrosion, deformation and mechanical 
damage (e.g., dents, gouges and grooves), material cracking and crack-
like defects (e.g., stress corrosion cracking, selective seam weld 
corrosion, environmentally assisted cracking, and girth weld cracks), 
hard spots with cracking, and any other threats to which the covered 
segment is susceptible. When performing an assessment using an in-line 
inspection tool, an operator must comply with Sec.  192.493;
    (2) Pressure test. Pressure test conducted in accordance with 
subpart J of this part. The use of subpart J pressure testing is 
appropriate for threats such as internal corrosion, external corrosion, 
and other environmentally assisted corrosion mechanisms; manufacturing 
and related defect threats, including defective pipe and pipe seams; 
and stress corrosion cracking, selective seam weld corrosion, dents and 
other forms of mechanical damage;
    (3) Spike hydrostatic pressure test. A spike hydrostatic pressure 
test conducted in accordance with Sec.  192.506. A spike hydrostatic 
pressure test is appropriate for time-dependent threats such as stress 
corrosion cracking; selective seam weld corrosion; manufacturing and 
related defects, including defective pipe and pipe seams; and other 
forms of defect or damage involving cracks or crack-like defects;
    (4) Direct examination. Excavation and in situ direct examination 
by means of visual examination, direct measurement, and recorded non-
destructive examination results and data needed to assess all 
applicable threats. Based upon the threat assessed, examples of 
appropriate non-destructive examination methods include ultrasonic 
testing (UT), phased array ultrasonic testing (PAUT), Inverse Wave 
Field Extrapolation (IWEX), radiography, and magnetic particle 
inspection (MPI);
    (5) Guided Wave Ultrasonic Testing. Guided Wave Ultrasonic Testing 
(GWUT) as described in Appendix F;
    (6) Direct assessment. Direct assessment to address threats of 
external corrosion, internal corrosion, and stress corrosion cracking. 
The use of use of direct assessment to address threats of external 
corrosion, internal corrosion, and stress corrosion cracking is allowed 
only if appropriate for the threat and pipeline segment being assessed. 
Use of direct assessment for threats other than the threat for which 
the direct assessment method is suitable is not allowed. An operator 
must conduct the direct assessment in accordance with the requirements 
listed in Sec.  192.923 and with the applicable requirements specified 
in Sec. Sec.  192.925, 192.927 and 192.929; or
    (7) Other technology. Other technology that an operator 
demonstrates can provide an equivalent understanding of the condition 
of the line pipe for each of the threats to which the pipeline is 
susceptible. An operator must notify PHMSA in advance of using the 
other technology in accordance with Sec.  192.18.
    (d) Data analysis. An operator must analyze and account for the 
data obtained from an assessment performed under paragraph (c) of this 
section to determine if a condition could adversely affect the safe 
operation of the pipeline using personnel qualified by knowledge, 
training, and experience. In addition, when analyzing inline inspection 
data, an operator must account for uncertainties in reported results 
(e.g., tool tolerance, detection threshold, probability of detection, 
probability of identification, sizing accuracy, conservative anomaly 
interaction criteria, location accuracy, anomaly findings, and unity 
chart plots or equivalent for determining uncertainties and verifying 
actual tool performance) in identifying and characterizing anomalies.
    (e) Discovery of condition. Discovery of a condition occurs when an 
operator has adequate information about a condition to determine that 
the condition presents a potential threat to the integrity of the 
pipeline. An operator must promptly, but no later than 180 days after 
conducting an integrity assessment, obtain sufficient information about 
a condition to make that determination, unless the operator 
demonstrates that 180 days is impracticable.
    (f) Remediation. An operator must comply with the requirements in 
Sec. Sec.  192.485, 192.711, and 192.713, where applicable, if a 
condition that could adversely affect the safe operation of a pipeline 
is discovered.
    (g) Analysis of information. An operator must analyze and account 
for all available relevant information about a pipeline in complying 
with the requirements in paragraphs (a) through (f) of this section.

0
25. Section 192.712 is added to read as follows:

Sec.  192.712   Analysis of predicted failure pressure.

    (a) Applicability. Whenever required by this part, operators of 
onshore steel transmission pipelines must analyze anomalies or defects 
to determine the predicted failure pressure at the location of the 
anomaly or defect, and the remaining life of the pipeline segment at 
the location of the anomaly or defect, in accordance with this section.
    (b) Corrosion metal loss. When analyzing corrosion metal loss under 
this section, an operator must use a suitable remaining strength 
calculation method including, ASME/ANSI B31G (incorporated by 
reference, see Sec.  192.7); R-STRENG (incorporated by reference, see 
Sec.  192.7); or an alternative equivalent method of remaining strength 
calculation that will provide an equally conservative result.
    (c) [Reserved]
    (d) Cracks and crack-like defects--(1) Crack analysis models. When 
analyzing cracks and crack-like defects under this section, an operator 
must determine predicted failure pressure, failure stress pressure, and 
crack growth using a technically proven fracture mechanics model 
appropriate to the failure mode (ductile, brittle or both), material 
properties (pipe and weld properties), and boundary condition used 
(pressure test, ILI, or other).
    (2) Analysis for crack growth and remaining life. If the pipeline 
segment is susceptible to cyclic fatigue or other loading conditions 
that could lead to fatigue crack growth, fatigue analysis must be 
performed using an applicable fatigue crack growth law (for example, 
Paris Law) or other technically appropriate engineering methodology. 
For other degradation processes that can cause crack growth, 
appropriate engineering analysis must be used. The above methodologies 
must be validated by a subject matter expert to determine conservative 
predictions of flaw growth and remaining life at the maximum allowable 
operating pressure. The operator must calculate the remaining life of 
the pipeline by determining the amount of time required for the crack 
to grow to a size that would fail at maximum allowable operating 
pressure.
    (i) When calculating crack size that would fail at MAOP, and the 
material toughness is not documented in traceable, verifiable, and 
complete records, the same Charpy v-notch toughness value established 
in paragraph (e)(2) of this section must be used.
    (ii) Initial and final flaw size must be determined using a 
fracture mechanics model appropriate to the failure mode (ductile, 
brittle or both) and boundary condition used (pressure test, ILI, or 
other).
    (iii) An operator must re-evaluate the remaining life of the 
pipeline before 50% of the remaining life calculated by this analysis 
has expired. The operator must determine and document if further 
pressure tests or use of other assessment

[[Page 52252]]

methods are required at that time. The operator must continue to re-
evaluate the remaining life of the pipeline before 50% of the remaining 
life calculated in the most recent evaluation has expired.
    (3) Cracks that survive pressure testing. For cases in which the 
operator does not have in-line inspection crack anomaly data and is 
analyzing potential crack defects that could have survived a pressure 
test, the operator must calculate the largest potential crack defect 
sizes using the methods in paragraph (d)(1) of this section. If pipe 
material toughness is not documented in traceable, verifiable, and 
complete records, the operator must use one of the following for Charpy 
v-notch toughness values based upon minimum operational temperature and 
equivalent to a full-size specimen value:
    (i) Charpy v-notch toughness values from comparable pipe with known 
properties of the same vintage and from the same steel and pipe 
manufacturer;
    (ii) A conservative Charpy v-notch toughness value to determine the 
toughness based upon the material properties verification process 
specified in Sec.  192.607;
    (iii) A full size equivalent Charpy v-notch upper-shelf toughness 
level of 120 ft.-lbs.; or
    (iv) Other appropriate values that an operator demonstrates can 
provide conservative Charpy v-notch toughness values of the crack-
related conditions of the pipeline segment. Operators using an assumed 
Charpy v-notch toughness value must notify PHMSA in accordance with 
Sec.  192.18.
    (e) Data. In performing the analyses of predicted or assumed 
anomalies or defects in accordance with this section, an operator must 
use data as follows.
    (1) An operator must explicitly analyze and account for 
uncertainties in reported assessment results (including tool tolerance, 
detection threshold, probability of detection, probability of 
identification, sizing accuracy, conservative anomaly interaction 
criteria, location accuracy, anomaly findings, and unity chart plots or 
equivalent for determining uncertainties and verifying tool 
performance) in identifying and characterizing the type and dimensions 
of anomalies or defects used in the analyses, unless the defect 
dimensions have been verified using in situ direct measurements.
    (2) The analyses performed in accordance with this section must 
utilize pipe and material properties that are documented in traceable, 
verifiable, and complete records. If documented data required for any 
analysis is not available, an operator must obtain the undocumented 
data through Sec.  192.607. Until documented material properties are 
available, the operator shall use conservative assumptions as follows:
    (i) Material toughness. An operator must use one of the following 
for material toughness:
    (A) Charpy v-notch toughness values from comparable pipe with known 
properties of the same vintage and from the same steel and pipe 
manufacturer;
    (B) A conservative Charpy v-notch toughness value to determine the 
toughness based upon the ongoing material properties verification 
process specified in Sec.  192.607;
    (C) If the pipeline segment does not have a history of reportable 
incidents caused by cracking or crack-like defects, maximum Charpy v-
notch toughness values of 13.0 ft.-lbs. for body cracks and 4.0 ft.-
lbs. for cold weld, lack of fusion, and selective seam weld corrosion 
defects;
    (D) If the pipeline segment has a history of reportable incidents 
caused by cracking or crack-like defects, maximum Charpy v-notch 
toughness values of 5.0 ft.-lbs. for body cracks and 1.0 ft.-lbs. for 
cold weld, lack of fusion, and selective seam weld corrosion; or
    (E) Other appropriate values that an operator demonstrates can 
provide conservative Charpy v-notch toughness values of crack-related 
conditions of the pipeline segment. Operators using an assumed Charpy 
v-notch toughness value must notify PHMSA in advance in accordance with 
Sec.  192.18 and include in the notification the bases for 
demonstrating that the Charpy v-notch toughness values proposed are 
appropriate and conservative for use in analysis of crack-related 
conditions.
    (ii) Material strength. An operator must assume one of the 
following for material strength:
    (A) Grade A pipe (30,000 psi), or
    (B) The specified minimum yield strength that is the basis for the 
current maximum allowable operating pressure.
    (iii) Pipe dimensions and other data. Until pipe wall thickness, 
diameter, or other data are determined and documented in accordance 
with Sec.  192.607, the operator must use values upon which the current 
MAOP is based.
    (f) Review. Analyses conducted in accordance with this section must 
be reviewed and confirmed by a subject matter expert.
    (g) Records. An operator must keep for the life of the pipeline 
records of the investigations, analyses, and other actions taken in 
accordance with the requirements of this section. Records must document 
justifications, deviations, and determinations made for the following, 
as applicable:
    (1) The technical approach used for the analysis;
    (2) All data used and analyzed;
    (3) Pipe and weld properties;
    (4) Procedures used;
    (5) Evaluation methodology used;
    (6) Models used;
    (7) Direct in situ examination data;
    (8) In-line inspection tool run information evaluated, including 
any multiple in-line inspection tool runs;
    (9) Pressure test data and results;
    (10) In-the-ditch assessments;
    (11) All measurement tool, assessment, and evaluation accuracy 
specifications and tolerances used in technical and operational 
results;
    (12) All finite element analysis results;
    (13) The number of pressure cycles to failure, the equivalent 
number of annual pressure cycles, and the pressure cycle counting 
method;
    (14) The predicted fatigue life and predicted failure pressure from 
the required fatigue life models and fracture mechanics evaluation 
methods;
    (15) Safety factors used for fatigue life and/or predicted failure 
pressure calculations;
    (16) Reassessment time interval and safety factors;
    (17) The date of the review;
    (18) Confirmation of the results by qualified technical subject 
matter experts; and
    (19) Approval by responsible operator management personnel.

0
26. Section 192.750 is added to read as follows:

Sec.  192.750  Launcher and receiver safety.

    Any launcher or receiver used after July 1, 2021, must be equipped 
with a device capable of safely relieving pressure in the barrel before 
removal or opening of the launcher or receiver barrel closure or flange 
and insertion or removal of in-line inspection tools, scrapers, or 
spheres. An operator must use a device to either: Indicate that 
pressure has been relieved in the barrel; or alternatively prevent 
opening of the barrel closure or flange when pressurized, or insertion 
or removal of in-line devices (e.g. inspection tools, scrapers, or 
spheres), if pressure has not been relieved.

0
27. In Sec.  192.805, paragraph (i) is revised to read as follows:

Sec.  192.805  Qualification Program.

* * * * *
    (i) After December 16, 2004, notify the Administrator or a state 
agency participating under 49 U.S.C. Chapter 601 if an operator 
significantly modifies the program after the administrator or state 
agency has verified that it complies

[[Page 52253]]

with this section. Notifications to PHMSA must be submitted in 
accordance with Sec.  192.18.

0
28. In Sec.  192.909, paragraph (b) is revised to read as follows:

Sec.  192.909  How can an operator change its integrity management 
program?

* * * * *
    (b) Notification. An operator must notify OPS, in accordance with 
Sec.  192.18, of any change to the program that may substantially 
affect the program's implementation or may significantly modify the 
program or schedule for carrying out the program elements. An operator 
must provide notification within 30 days after adopting this type of 
change into its program.

0
29. In Sec.  192.917, paragraphs (a)(3) and (e)(2) through (4) are 
revised, and paragraph (e)(6) is added to read as follows:

Sec.  192.917   How does an operator identify potential threats to 
pipeline integrity and use the threat identification in its integrity 
program?

    (a) * * *
    (3) Time independent threats such as third party damage, mechanical 
damage, incorrect operational procedure, weather related and outside 
force damage to include consideration of seismicity, geology, and soil 
stability of the area; and
* * * * *
    (e) * * *
    (2) Cyclic fatigue. An operator must analyze and account for 
whether cyclic fatigue or other loading conditions (including ground 
movement, and suspension bridge condition) could lead to a failure of a 
deformation, including a dent or gouge, crack, or other defect in the 
covered segment. The analysis must assume the presence of threats in 
the covered segment that could be exacerbated by cyclic fatigue. An 
operator must use the results from the analysis together with the 
criteria used to determine the significance of the threat(s) to the 
covered segment to prioritize the integrity baseline assessment or 
reassessment. Failure stress pressure and crack growth analysis of 
cracks and crack-like defects must be conducted in accordance with 
Sec.  192.712. An operator must monitor operating pressure cycles and 
periodically, but at least every 7 calendar years, with intervals not 
to exceed 90 months, determine if the cyclic fatigue analysis remains 
valid or if the cyclic fatigue analysis must be revised based on 
changes to operating pressure cycles or other loading conditions.
    (3) Manufacturing and construction defects. An operator must 
analyze the covered segment to determine and account for the risk of 
failure from manufacturing and construction defects (including seam 
defects) in the covered segment. The analysis must account for the 
results of prior assessments on the covered segment. An operator may 
consider manufacturing and construction related defects to be stable 
defects only if the covered segment has been subjected to hydrostatic 
pressure testing satisfying the criteria of subpart J of at least 1.25 
times MAOP, and the covered segment has not experienced a reportable 
incident attributed to a manufacturing or construction defect since the 
date of the most recent subpart J pressure test. If any of the 
following changes occur in the covered segment, an operator must 
prioritize the covered segment as a high-risk segment for the baseline 
assessment or a subsequent reassessment.
    (i) The pipeline segment has experienced a reportable incident, as 
defined in Sec.  191.3, since its most recent successful subpart J 
pressure test, due to an original manufacturing-related defect, or a 
construction-, installation-, or fabrication-related defect;
    (ii) MAOP increases; or
    (iii) The stresses leading to cyclic fatigue increase.
    (4) Electric Resistance Welded (ERW) pipe. If a covered pipeline 
segment contains low frequency ERW pipe, lap welded pipe, pipe with 
longitudinal joint factor less than 1.0 as defined in Sec.  192.113, or 
other pipe that satisfies the conditions specified in ASME/ANSI B31.8S, 
Appendices A4.3 and A4.4, and any covered or non-covered segment in the 
pipeline system with such pipe has experienced seam failure (including 
seam cracking and selective seam weld corrosion), or operating pressure 
on the covered segment has increased over the maximum operating 
pressure experienced during the preceding 5 years (including abnormal 
operation as defined in Sec.  192.605(c)), or MAOP has been increased, 
an operator must select an assessment technology or technologies with a 
proven application capable of assessing seam integrity and seam 
corrosion anomalies. The operator must prioritize the covered segment 
as a high-risk segment for the baseline assessment or a subsequent 
reassessment. Pipe with seam cracks must be evaluated using fracture 
mechanics modeling for failure stress pressures and cyclic fatigue 
crack growth analysis to estimate the remaining life of the pipe in 
accordance with Sec.  192.712.
* * * * *
    (6) Cracks. If an operator identifies any crack or crack-like 
defect (e.g., stress corrosion cracking or other environmentally 
assisted cracking, seam defects, selective seam weld corrosion, girth 
weld cracks, hook cracks, and fatigue cracks) on a covered pipeline 
segment that could adversely affect the integrity of the pipeline, the 
operator must evaluate, and remediate, as necessary, all pipeline 
segments (both covered and non-covered) with similar characteristics 
associated with the crack or crack-like defect. Similar characteristics 
may include operating and maintenance histories, material properties, 
and environmental characteristics. An operator must establish a 
schedule for evaluating, and remediating, as necessary, the similar 
pipeline segments that is consistent with the operator's established 
operating and maintenance procedures under this part for testing and 
repair.

0
30. In Sec.  192.921, revise paragraph (a) and add paragraph (i) to 
read as follows:

Sec.  192.921  How is the baseline assessment to be conducted?

    (a) Assessment methods. An operator must assess the integrity of 
the line pipe in each covered segment by applying one or more of the 
following methods for each threat to which the covered segment is 
susceptible. An operator must select the method or methods best suited 
to address the threats identified to the covered segment (See Sec.  
192.917).
    (1) Internal inspection tool or tools capable of detecting those 
threats to which the pipeline is susceptible. The use of internal 
inspection tools is appropriate for threats such as corrosion, 
deformation and mechanical damage (including dents, gouges and 
grooves), material cracking and crack-like defects (e.g., stress 
corrosion cracking, selective seam weld corrosion, environmentally 
assisted cracking, and girth weld cracks), hard spots with cracking, 
and any other threats to which the covered segment is susceptible. When 
performing an assessment using an in-line inspection tool, an operator 
must comply with Sec.  192.493. In addition, an operator must analyze 
and account for uncertainties in reported results (e.g., tool 
tolerance, detection threshold, probability of detection, probability 
of identification, sizing accuracy, conservative anomaly interaction 
criteria, location accuracy, anomaly findings, and unity chart plots or 
equivalent for determining uncertainties and verifying actual tool

[[Page 52254]]

performance) in identifying and characterizing anomalies;
    (2) Pressure test conducted in accordance with subpart J of this 
part. The use of subpart J pressure testing is appropriate for threats 
such as internal corrosion; external corrosion and other 
environmentally assisted corrosion mechanisms; manufacturing and 
related defects threats, including defective pipe and pipe seams; 
stress corrosion cracking; selective seam weld corrosion; dents; and 
other forms of mechanical damage. An operator must use the test 
pressures specified in Table 3 of section 5 of ASME/ANSI B31.8S 
(incorporated by reference, see Sec.  192.7) to justify an extended 
reassessment interval in accordance with Sec.  192.939.
    (3) Spike hydrostatic pressure test conducted in accordance with 
Sec.  192.506. The use of spike hydrostatic pressure testing is 
appropriate for time-dependent threats such as stress corrosion 
cracking; selective seam weld corrosion; manufacturing and related 
defects, including defective pipe and pipe seams; and other forms of 
defect or damage involving cracks or crack-like defects;
    (4) Excavation and in situ direct examination by means of visual 
examination, direct measurement, and recorded non-destructive 
examination results and data needed to assess all threats. Based upon 
the threat assessed, examples of appropriate non-destructive 
examination methods include ultrasonic testing (UT), phased array 
ultrasonic testing (PAUT), inverse wave field extrapolation (IWEX), 
radiography, and magnetic particle inspection (MPI);
    (5) Guided wave ultrasonic testing (GWUT) as described in Appendix 
F. The use of GWUT is appropriate for internal and external pipe wall 
loss;
    (6) Direct assessment to address threats of external corrosion, 
internal corrosion, and stress corrosion cracking. The use of direct 
assessment to address threats of external corrosion, internal 
corrosion, and stress corrosion cracking is allowed only if appropriate 
for the threat and the pipeline segment being assessed. Use of direct 
assessment for threats other than the threat for which the direct 
assessment method is suitable is not allowed. An operator must conduct 
the direct assessment in accordance with the requirements listed in 
Sec.  192.923 and with the applicable requirements specified in 
Sec. Sec.  192.925, 192.927 and 192.929; or
    (7) Other technology that an operator demonstrates can provide an 
equivalent understanding of the condition of the line pipe for each of 
the threats to which the pipeline is susceptible. An operator must 
notify PHMSA in advance of using the other technology in accordance 
with Sec.  192.18.
* * * * *
    (i) Baseline assessments for pipeline segments with a reconfirmed 
MAOP. An integrity assessment conducted in accordance with the 
requirements of Sec.  192.624(c) may be used as a baseline assessment 
under this section.

0
31. In Sec.  192.933, paragraphs (a)(1) and (2) are revised to read as 
follows:

Sec.  192.933   What actions must be taken to address integrity issues?

    (a) * * *
    (1) Temporary pressure reduction. If an operator is unable to 
respond within the time limits for certain conditions specified in this 
section, the operator must temporarily reduce the operating pressure of 
the pipeline or take other action that ensures the safety of the 
covered segment. An operator must determine any temporary reduction in 
operating pressure required by this section using ASME/ANSI B31G 
(incorporated by reference, see Sec.  192.7); R-STRENG (incorporated by 
reference, see Sec.  192.7); or by reducing the operating pressure to a 
level not exceeding 80 percent of the level at the time the condition 
was discovered. An operator must notify PHMSA in accordance with Sec.  
192.18 if it cannot meet the schedule for evaluation and remediation 
required under paragraph (c) of this section and cannot provide safety 
through a temporary reduction in operating pressure or through another 
action.
    (2) Long-term pressure reduction. When a pressure reduction exceeds 
365 days, an operator must notify PHMSA under Sec.  192.18 and explain 
the reasons for the remediation delay. This notice must include a 
technical justification that the continued pressure reduction will not 
jeopardize the integrity of the pipeline.
* * * * *

0
32. In Sec.  192.935, paragraph (b)(2) is revised to read as follows:

Sec.  192.935  What additional preventive and mitigative measures must 
an operator take?

* * * * *
    (b) * * *
    (2) Outside force damage. If an operator determines that outside 
force (e.g., earth movement, loading, longitudinal, or lateral forces, 
seismicity of the area, floods, unstable suspension bridge) is a threat 
to the integrity of a covered segment, the operator must take measures 
to minimize the consequences to the covered segment from outside force 
damage. These measures include increasing the frequency of aerial, foot 
or other methods of patrols; adding external protection; reducing 
external stress; relocating the line; or inline inspections with 
geospatial and deformation tools.
* * * * *

0
33. In Sec.  192.937, revise paragraph (c) and add paragraph (d) to 
read as follows:

Sec.  192.937  What is a continual process of evaluation and assessment 
to maintain a pipeline's integrity?

* * * * *
    (c) Assessment methods. In conducting the integrity reassessment, 
an operator must assess the integrity of the line pipe in each covered 
segment by applying one or more of the following methods for each 
threat to which the covered segment is susceptible. An operator must 
select the method or methods best suited to address the threats 
identified on the covered segment (see Sec.  192.917).
    (1) Internal inspection tools. When performing an assessment using 
an in-line inspection tool, an operator must comply with the following 
requirements:
    (i) Perform the in-line inspection in accordance with Sec.  
192.493;
    (ii) Select a tool or combination of tools capable of detecting the 
threats to which the pipeline segment is susceptible such as corrosion, 
deformation and mechanical damage (e.g. dents, gouges and grooves), 
material cracking and crack-like defects (e.g. stress corrosion 
cracking, selective seam weld corrosion, environmentally assisted 
cracking, and girth weld cracks), hard spots with cracking, and any 
other threats to which the covered segment is susceptible; and
    (iii) Analyze and account for uncertainties in reported results 
(e.g., tool tolerance, detection threshold, probability of detection, 
probability of identification, sizing accuracy, conservative anomaly 
interaction criteria, location accuracy, anomaly findings, and unity 
chart plots or equivalent for determining uncertainties and verifying 
actual tool performance) in identifying and characterizing anomalies.
    (2) Pressure test conducted in accordance with subpart J of this 
part. The use of pressure testing is appropriate for threats such as: 
Internal corrosion; external corrosion and other environmentally 
assisted corrosion mechanisms; manufacturing and related defects 
threats, including defective pipe and pipe seams; stress corrosion 
cracking; selective seam weld corrosion; dents; and other forms of 
mechanical damage. An operator must use the test

[[Page 52255]]

pressures specified in table 3 of section 5 of ASME/ANSI B31.8S 
(incorporated by reference, see Sec.  192.7) to justify an extended 
reassessment interval in accordance with Sec.  192.939.
    (3) Spike hydrostatic pressure test in accordance with Sec.  
192.506. The use of spike hydrostatic pressure testing is appropriate 
for time-dependent threats such as: Stress corrosion cracking; 
selective seam weld corrosion; manufacturing and related defects, 
including defective pipe and pipe seams; and other forms of defect or 
damage involving cracks or crack-like defects;
    (4) Excavation and in situ direct examination by means of visual 
examination, direct measurement, and recorded non-destructive 
examination results and data needed to assess all threats. Based upon 
the threat assessed, examples of appropriate non-destructive 
examination methods include ultrasonic testing (UT), phased array 
ultrasonic testing (PAUT), inverse wave field extrapolation (IWEX), 
radiography, or magnetic particle inspection (MPI);
    (5) Guided wave ultrasonic testing (GWUT) as described in Appendix 
F. The use of GWUT is appropriate for internal and external pipe wall 
loss;
    (6) Direct assessment to address threats of external corrosion, 
internal corrosion, and stress corrosion cracking. The use of direct 
assessment to address threats of external corrosion, internal 
corrosion, and stress corrosion cracking is allowed only if appropriate 
for the threat and pipeline segment being assessed. Use of direct 
assessment for threats other than the threat for which the direct 
assessment method is suitable is not allowed. An operator must conduct 
the direct assessment in accordance with the requirements listed in 
Sec.  192.923 and with the applicable requirements specified in 
Sec. Sec.  192.925, 192.927, and 192.929;
    (7) Other technology that an operator demonstrates can provide an 
equivalent understanding of the condition of the line pipe for each of 
the threats to which the pipeline is susceptible. An operator must 
notify PHMSA in advance of using the other technology in accordance 
with Sec.  192.18; or
    (8) Confirmatory direct assessment when used on a covered segment 
that is scheduled for reassessment at a period longer than 7 calendar 
years. An operator using this reassessment method must comply with 
Sec.  192.931.
    (d) MAOP reconfirmation assessments. An integrity assessment 
conducted in accordance with the requirements of Sec.  192.624(c) may 
be used as a reassessment under this section.

0
34. In Sec.  192.939, paragraphs (a) introductory text, (b) 
introductory text, and (b)(1) are revised to read as follows:

Sec.  192.939  What are the required reassessment intervals?

* * * * *
    (a) Pipelines operating at or above 30% SMYS. An operator must 
establish a reassessment interval for each covered segment operating at 
or above 30% SMYS in accordance with the requirements of this section. 
The maximum reassessment interval by an allowable reassessment method 
is 7 calendar years. Operators may request a 6-month extension of the 
7-calendar-year reassessment interval if the operator submits written 
notice to OPS, in accordance with Sec.  192.18, with sufficient 
justification of the need for the extension. If an operator establishes 
a reassessment interval that is greater than 7 calendar years, the 
operator must, within the 7-calendar-year period, conduct a 
confirmatory direct assessment on the covered segment, and then conduct 
the follow-up reassessment at the interval the operator has 
established. A reassessment carried out using confirmatory direct 
assessment must be done in accordance with Sec.  192.931. The table 
that follows this section sets forth the maximum allowed reassessment 
intervals.
* * * * *
    (b) Pipelines Operating below 30% SMYS. An operator must establish 
a reassessment interval for each covered segment operating below 30% 
SMYS in accordance with the requirements of this section. The maximum 
reassessment interval by an allowable reassessment method is 7 calendar 
years. Operators may request a 6-month extension of the 7-calendar-year 
reassessment interval if the operator submits written notice to OPS in 
accordance with Sec.  192.18. The notice must include sufficient 
justification of the need for the extension. An operator must establish 
reassessment by at least one of the following--
    (1) Reassessment by pressure test, internal inspection or other 
equivalent technology following the requirements in paragraph (a)(1) of 
this section except that the stress level referenced in paragraph 
(a)(1)(ii) of this section would be adjusted to reflect the lower 
operating stress level. If an established interval is more than 7 
calendar years, an operator must conduct by the seventh calendar year 
of the interval either a confirmatory direct assessment in accordance 
with Sec.  192.931, or a low stress reassessment in accordance with 
Sec.  192.941.
* * * * *

Sec.  192.949  [Removed and Reserved]

0
35. Remove and reserve Sec.  192.949.

0
36. Appendix F is added to read as follows:

Appendix F to Part 192-Criteria for Conducting Integrity Assessments 
Using Guided Wave Ultrasonic Testing (GWUT)

    This appendix defines criteria which must be properly implemented 
for use of guided wave ultrasonic testing (GWUT) as an integrity 
assessment method. Any application of GWUT that does not conform to 
these criteria is considered ``other technology'' as described by 
Sec. Sec.  192.710(c)(7), 192.921(a)(7), and 192.937(c)(7), for which 
OPS must be notified 90 days prior to use in accordance with Sec. Sec.  
192.921(a)(7) or 192.937(c)(7). GWUT in the ``Go-No Go'' mode means 
that all indications (wall loss anomalies) above the testing threshold 
(a maximum of 5% of cross sectional area (CSA) sensitivity) be directly 
examined, in-line tool inspected, pressure tested, or replaced prior to 
completing the integrity assessment on the carrier pipe.
    I. Equipment and Software: Generation. The equipment and the 
computer software used are critical to the success of the inspection. 
Computer software for the inspection equipment must be reviewed and 
updated, as required, on an annual basis, with intervals not to exceed 
15 months, to support sensors, enhance functionality, and resolve any 
technical or operational issues identified.
    II. Inspection Range. The inspection range and sensitivity are set 
by the signal to noise (S/N) ratio but must still keep the maximum 
threshold sensitivity at 5% cross sectional area (CSA). A signal that 
has an amplitude that is at least twice the noise level can be reliably 
interpreted. The greater the S/N ratio the easier it is to identify and 
interpret signals from small changes. The signal to noise ratio is 
dependent on several variables such as surface roughness, coating, 
coating condition, associated pipe fittings (T's, elbows, flanges), 
soil compaction, and environment. Each of these affects the propagation 
of sound waves and influences the range of the test. It may be 
necessary to inspect from both ends of the pipeline segment to achieve 
a full inspection. In general, the inspection range can approach 60 to 
100 feet for a 5% CSA, depending on field conditions.
    III. Complete Pipe Inspection. To ensure that the entire pipeline 
segment is assessed there should be at least a 2 to 1 signal to noise 
ratio across the entire pipeline segment that is

[[Page 52256]]

inspected. This may require multiple GWUT shots. Double-ended 
inspections are expected. These two inspections are to be overlaid to 
show the minimum 2 to 1 S/N ratio is met in the middle. If possible, 
show the same near or midpoint feature from both sides and show an 
approximate 5% distance overlap.
    IV. Sensitivity. The detection sensitivity threshold determines the 
ability to identify a cross sectional change. The maximum threshold 
sensitivity cannot be greater than 5% of the cross sectional area 
(CSA).
    The locations and estimated CSA of all metal loss features in 
excess of the detection threshold must be determined and documented.
    All defect indications in the ``Go-No Go'' mode above the 5% 
testing threshold must be directly examined, in-line inspected, 
pressure tested, or replaced prior to completing the integrity 
assessment.
    V. Wave Frequency. Because a single wave frequency may not detect 
certain defects, a minimum of three frequencies must be run for each 
inspection to determine the best frequency for characterizing 
indications. The frequencies used for the inspections must be 
documented and must be in the range specified by the manufacturer of 
the equipment.
    VI. Signal or Wave Type: Torsional and Longitudinal. Both torsional 
and longitudinal waves must be used and use must be documented.
    VII. Distance Amplitude Correction (DAC) Curve and Weld 
Calibration. The distance amplitude correction curve accounts for 
coating, pipe diameter, pipe wall and environmental conditions at the 
assessment location. The DAC curve must be set for each inspection as 
part of establishing the effective range of a GWUT inspection. DAC 
curves provide a means for evaluating the cross-sectional area change 
of reflections at various distances in the test range by assessing 
signal to noise ratio. A DAC curve is a means of taking apparent 
attenuation into account along the time base of a test signal. It is a 
line of equal sensitivity along the trace which allows the amplitudes 
of signals at different axial distances from the collar to be compared.
    VIII. Dead Zone. The dead zone is the area adjacent to the collar 
in which the transmitted signal blinds the received signal, making it 
impossible to obtain reliable results. Because the entire line must be 
inspected, inspection procedures must account for the dead zone by 
requiring the movement of the collar for additional inspections. An 
alternate method of obtaining valid readings in the dead zone is to use 
B-scan ultrasonic equipment and visual examination of the external 
surface. The length of the dead zone and the near field for each 
inspection must be documented.
    IX. Near Field Effects. The near field is the region beyond the 
dead zone where the receiving amplifiers are increasing in power, 
before the wave is properly established. Because the entire line must 
be inspected, inspection procedures must account for the near field by 
requiring the movement of the collar for additional inspections. An 
alternate method of obtaining valid readings in the near field is to 
use B-scan ultrasonic equipment and visual examination of the external 
surface. The length of the dead zone and the near field for each 
inspection must be documented.
    X. Coating Type. Coatings can have the effect of attenuating the 
signal. Their thickness and condition are the primary factors that 
affect the rate of signal attenuation. Due to their variability, 
coatings make it difficult to predict the effective inspection 
distance. Several coating types may affect the GWUT results to the 
point that they may reduce the expected inspection distance. For 
example, concrete coated pipe may be problematic when well bonded due 
to the attenuation effects. If an inspection is done and the required 
sensitivity is not achieved for the entire length of the pipe, then 
another type of assessment method must be utilized.
    XI. End Seal. When assessing cased carrier pipe with GWUT, 
operators must remove the end seal from the casing at each GWUT test 
location to facilitate visual inspection. Operators must remove debris 
and water from the casing at the end seals. Any corrosion material 
observed must be removed, collected and reviewed by the operator's 
corrosion technician. The end seal does not interfere with the accuracy 
of the GWUT inspection but may have a dampening effect on the range.
    XII. Weld Calibration to set DAC Curve. Accessible welds, along or 
outside the pipeline segment to be inspected, must be used to set the 
DAC curve. A weld or welds in the access hole (secondary area) may be 
used if welds along the pipeline segment are not accessible. In order 
to use these welds in the secondary area, sufficient distance must be 
allowed to account for the dead zone and near field. There must not be 
a weld between the transducer collar and the calibration weld. A 
conservative estimate of the predicted amplitude for the weld is 25% 
CSA (cross sectional area) and can be used if welds are not accessible. 
Calibrations (setting of the DAC curve) should be on pipe with similar 
properties such as wall thickness and coating. If the actual weld cap 
height is different from the assumed weld cap height, the estimated CSA 
may be inaccurate and adjustments to the DAC curve may be required. 
Alternative means of calibration can be used if justified by a 
documented engineering analysis and evaluation.
    XIII. Validation of Operator Training. Pipeline operators must 
require all guided wave service providers to have equipment-specific 
training and experience for all GWUT Equipment Operators which includes 
training for:
    A. Equipment operation,
    B. field data collection, and
    C. data interpretation on cased and buried pipe.
    Only individuals who have been qualified by the manufacturer or an 
independently assessed evaluation procedure similar to ISO 9712 
(Sections: 5 Responsibilities; 6 Levels of Qualification; 7 
Eligibility; and 10 Certification), as specified above, may operate the 
equipment. A senior-level GWUT equipment operator with pipeline 
specific experience must provide onsite oversight of the inspection and 
approve the final reports. A senior-level GWUT equipment operator must 
have additional training and experience, including training specific to 
cased and buried pipe, with a quality control program which that 
conforms to Section 12 of ASME B31.8S (for availability, see Sec.  
192.7).
    XIV. Training and Experience Minimums for Senior Level GWUT 
Equipment Operators:
     Equipment Manufacturer's minimum qualification for 
equipment operation and data collection with specific endorsements for 
casings and buried pipe
     Training, qualification and experience in testing 
procedures and frequency determination
     Training, qualification and experience in conversion of 
guided wave data into pipe features and estimated metal loss (estimated 
cross-sectional area loss and circumferential extent)
     Equipment Manufacturer's minimum qualification with 
specific endorsements for data interpretation of anomaly features for 
pipe within casings and buried pipe.
    XV. Equipment: Traceable from vendor to inspection company. An 
operator must maintain documentation of the version of the GWUT 
software used and the serial number of the other

[[Page 52257]]

equipment such as collars, cables, etc., in the report.
    XVI. Calibration Onsite. The GWUT equipment must be calibrated for 
performance in accordance with the manufacturer's requirements and 
specifications, including the frequency of calibrations. A diagnostic 
check and system check must be performed on-site each time the 
equipment is relocated to a different casing or pipeline segment. If 
on-site diagnostics show a discrepancy with the manufacturer's 
requirements and specifications, testing must cease until the equipment 
can be restored to manufacturer's specifications.
    XVII. Use on Shorted Casings (direct or electrolytic). GWUT may not 
be used to assess shorted casings. GWUT operators must have operations 
and maintenance procedures (see Sec.  192.605) to address the effect of 
shorted casings on the GWUT signal. The equipment operator must clear 
any evidence of interference, other than some slight dampening of the 
GWUT signal from the shorted casing, according to their operating and 
maintenance procedures. All shorted casings found while conducting GWUT 
inspections must be addressed by the operator's standard operating 
procedures.
    XVIII. Direct examination of all indications above the detection 
sensitivity threshold. The use of GWUT in the ``Go-No Go'' mode 
requires that all indications (wall loss anomalies) above the testing 
threshold (5% of CSA sensitivity) be directly examined (or replaced) 
prior to completing the integrity assessment on the cased carrier pipe 
or other GWUT application. If this cannot be accomplished, then 
alternative methods of assessment (such as hydrostatic pressure tests 
or ILI) must be utilized.
    XIV. Timing of direct examination of all indications above the 
detection sensitivity threshold. Operators must either replace or 
conduct direct examinations of all indications identified above the 
detection sensitivity threshold according to the table below. Operators 
must conduct leak surveys and reduce operating pressure as specified 
until the pipe is replaced or direct examinations are completed.

                                      Required Response to GWUT Indications
----------------------------------------------------------------------------------------------------------------
                                      Operating pressure   Operating pressure over 30
          GWUT criterion            less than or equal to   and less than or equal to   Operating pressure over
                                           30% SMYS                 50% SMYS                    50% SMYS
----------------------------------------------------------------------------------------------------------------
Over the detection sensitivity      Replace or direct      Replace or direct           Replace or direct
 threshold (maximum of 5% CSA).      examination within     examination within 6        examination within 6
                                     12 months, and         months, instrumented leak   months, instrumented
                                     instrumented leak      survey once every 30        leak survey once every
                                     survey once every 30   calendar days, and          30 calendar days, and
                                     calendar days.         maintain MAOP below the     reduce MAOP to 80% of
                                                            operating pressure at       operating pressure at
                                                            time of discovery.          time of discovery.
----------------------------------------------------------------------------------------------------------------

    Issued in Washington, DC, on September 16, 2019, under authority 
delegated in 49 CFR part 1.97.
Howard R. Elliott,
Administrator.
[FR Doc. 2019-20306 Filed 9-30-19; 8:45 am]
 BILLING CODE 4910-60-P