Document ID: PHMSA-2017-0151-0031
Agency: phmsa
Document Type: Proposed Rule
Title: Pipeline Safety: Class Location Change Requirements
Posted Date: 2020-10-14T04:00Z

[Federal Register Volume 85, Number 199 (Wednesday, October 14, 2020)]
[Proposed Rules]
[Pages 65142-65178]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2020-19872]

[[Page 65141]]

Vol. 85

Wednesday,

No. 199

October 14, 2020

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: Class Location Change Requirements; Proposed Rule

  Federal Register / Vol. 85 , No. 199 / Wednesday, October 14, 2020 / 
Proposed Rules  

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DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous Materials Safety Administration

49 CFR Parts 191 and 192

[Docket No. PHMSA-2017-0151]
RIN 2137-AF29

Pipeline Safety: Class Location Change Requirements

AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA); 
DOT.

ACTION: Notice of proposed rulemaking (NPRM).

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SUMMARY: In response to public input received as part of the rulemaking 
process, PHMSA is proposing to revise the Federal Pipeline Safety 
Regulations to amend the requirements for gas transmission pipeline 
segments that experience a change in class location. Under the existing 
regulations, pipeline segments located in areas where the population 
density has significantly increased must perform one of the following 
actions: Reduce the pressure of the pipeline segment, pressure test the 
pipeline segment to higher standards, or replace the pipeline segment. 
This proposed rule would add an alternative set of requirements 
operators could use, based on implementing integrity management 
principles and pipe eligibility criteria, to manage certain pipeline 
segments where the class location has changed from a Class 1 location 
to a Class 3 location. Through required periodic assessments, repair 
criteria, and other extra preventive and mitigative measures, PHMSA 
expects this alternative approach would provide long-term safety 
benefits consistent with the current natural gas pipeline safety rules 
while also providing cost savings for pipeline operators.

DATES: Persons interested in submitting written comments on this 
proposed rule must do so by December 14, 2020. Late-filed comments will 
be considered to the extent practicable.

ADDRESSES: You may submit comments identified by the docket number 
PHMSA-2017-0151 by any of the following methods:
    Federal eRulemaking Portal: https://www.regulations.gov. This site 
allows the public to enter comments on any Federal Register notice 
issued by any agency. Follow the online instructions for submitting 
comments.
    Mail: Hand Delivery: U.S. DOT Docket Management System, West 
Building Ground Floor, Room W12-140, 1200 New Jersey Avenue SE, 
Washington, DC 20590-0001 between 9:00 a.m. and 5:00 p.m., Monday 
through Friday, except Federal holidays.
    Fax: 1-202-493-2251.
    Instructions: Identify the docket number PHMSA-2017-0151 at the 
beginning of your comments. If you submit your comments by mail, submit 
two copies. If you wish to receive confirmation that PHMSA has received 
your comments, include a self-addressed stamped postcard. Internet 
users may submit comments at https://www.regulations.gov/.

    Note: Comments are posted without changes or edits to https://www.regulations.gov, including any personal information provided. 
There is a privacy statement published on https://www.regulations.gov.

Confidential Business Information

    Confidential Business Information (CBI) is commercial or financial 
information that is both customarily and actually treated as private by 
its owner. Under the Freedom of Information Act (FOIA) (5 U.S.C. 552), 
CBI is exempt from public disclosure. If your comments responsive to 
this notice contain commercial or financial information that is 
customarily treated as private, that you actually treat as private, and 
that is relevant or responsive to this notice, it is important that you 
clearly designate the submitted comments as CBI. Pursuant to 49 CFR 
190.343, you may ask PHMSA to give confidential treatment to 
information you give to the agency by taking the following steps: (1) 
Mark each page of the original document submission containing CBI as 
``Confidential''; (2) send PHMSA, along with the original document, a 
second copy of the original document with the CBI deleted; and (3) 
explain why the information you are submitting is CBI. Unless you are 
notified otherwise, PHMSA will treat such marked submissions as 
confidential under the FOIA, and they will not be placed in the public 
docket of this notice. Submissions containing CBI should be sent to 
Robert Jagger, Office of Pipeline Safety (PHP-30), Pipeline and 
Hazardous Materials Safety Administration (PHMSA), 2nd Floor, 1200 New 
Jersey Avenue SE, Washington, DC 20590-0001, or by email at 
robert.jagger@dot.gov. Any commentary PHMSA receives that is not 
specifically designated as CBI will be placed in the public docket.

FOR FURTHER INFORMATION CONTACT: Robert Jagger, Senior Transportation 
Specialist, by telephone at 202-366-4361. For technical questions: 
Steve Nanney, Project Manager, by telephone at 713-272-2855.

SUPPLEMENTARY INFORMATION:
I. Executive Summary
    A. Purpose of Regulatory Action
    B. Summary of the Major Regulatory Provisions
    C. Costs and Benefits
II. Background
    A. Class Location History and Purpose
    B. Changes in Class Location Due to Population Growth
    C. Class Location Change Special Permits
    D. Class Location Studies, Public Workshop, Report, and 
Stakeholder Input
    E. Class Location ANPRM
    F. 2019 Gas Transmission Final Rule
III. Analysis of ANPRM Comments and PHMSA's Response
    A. Comments Related to the 2016 Proposed Gas Transmission Rule
    B. Requiring Pipe Integrity Upgrades and Allowing Other Options 
for Class Location Changes
    C. Integrity Upgrades and Integrity Management Options for 
Clustered Areas
    D. Using an Integrity Management Option To Manage Safety When 
Class Locations Change From a Class 1 to a Class 3
    E. General Eligibility for Managing Class Location Changes With 
Integrity Management
    F. Eligibility for Pipe Operated in Accordance With Sec.  
192.619(c)
    G. Eligibility for Pipe With Specific Conditions and Attributes
    H. Eligibility for Pipe With Significant Corrosion
    I. Eligibility for Damaged Pipe, Dented Pipe, or Pipe That Has 
Lost Ground Cover
    J. Eligibility Factors Based on Diameter, Operating Pressure, or 
Potential Impact Radius Size
    K. Codifying Current Special Permit Conditions
    L. Additional Preventive and Mitigative Measures Needed for an 
Integrity Management Option for Class Location Change Management
    M. Traceable, Verifiable, and Complete Records for Supporting 
Class Location Change Integrity Management Measures
    N. Data on Class Location Pipe Replacement and Route Planning
    O. Other Topics--General Comments
IV. Section-by-Section Analysis
V. Regulatory Analyses and Notices

I. Executive Summary

A. Purpose of Regulatory Action

    Class locations are used in the natural gas Federal Pipeline Safety 
Regulations (PSR) in a graded approach to provide conservative safety 
margins \1\ and safety standards commensurate with the potential 
consequences of pipeline

[[Page 65143]]

incidents, and are based on the population density near a pipeline.\2\ 
As class locations are defined with relation to the number of dwellings 
for human occupancy in the area, an onshore gas transmission pipeline's 
class location can change as the population living or working near a 
pipeline changes. An increase in population that results in a change in 
class location requires operators to confirm design factors and to 
recalculate the maximum allowable operating pressure (MAOP) of the 
pipeline.\3\ If a class location changes and the hoop stress \4\ 
corresponding to the established MAOP of a segment of pipeline is not 
commensurate with the MAOP of the newly determined class location, 
Sec.  192.611 currently requires that the pipeline operator (1) lower 
the pipeline's MAOP to reduce stress levels in the pipe, (2) replace 
the existing pipe with pipe that has thicker walls or higher yield 
strength to yield a lower operating stress at the same MAOP, or (3) 
pressure test the pipeline at a higher test pressure.
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    \1\ Pipelines are designed with a safety margin between the 
design operating pressure and the pressure at which failure would 
occur. Safety margins are necessary because pipelines can be subject 
to emergency situations, unexpected loads, operator error, and 
material degradation.
    \2\ Class locations are defined at Sec.  192.5. A ``class 
location unit'' is defined at Sec.  192.5 as an onshore area that 
extends 220 yards on either side of the centerline of any continuous 
1-mile length of pipeline. This distance is more colloquially known 
as the ``sliding mile'' and is explained in more detail later in 
this document. A Class 1 location is an offshore area or any class 
location unit with 10 or fewer buildings intended for human 
occupancy within the class location unit. A Class 2 location is any 
class location unit with more than 10 but fewer than 46 buildings 
intended for human occupancy within the class location unit. A Class 
3 location is any class location unit with 46 or more buildings 
intended for human occupancy or an area where the pipeline lies 
within 100 yards of either a building or a small, well-defined 
outside area that is occupied by 20 or more persons on at least 5 
days a week for 10 weeks in any 12-month period within the class 
location unit, and a Class 4 location is any class location unit 
where buildings with 4 or more stories above ground are prevalent.
    \3\ Maximum allowable operating pressure is the maximum internal 
pressure at which a natural gas pipeline or pipeline segment may be 
operated.
    \4\ Hoop stress is stress that acts around the circumference of 
a pipe (i.e., perpendicular to the pipe length) and is caused by the 
internal pressure pushing outward against the pipe wall. As pressure 
within the pipe increases, the stress in the pipe wall must be 
capable of acting against that pressure to contain it.
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    Some operators have applied for special permits to manage class 
location changes that would normally require replacing pipe, reducing 
the operating pressure, or pressure testing the pipe. Under the special 
permit process, PHMSA waives or otherwise modifies compliance with 
regulatory requirements if the operator requesting the special permit 
demonstrates a need and PHMSA determines that granting the special 
permit would be consistent with pipeline safety.\5\ PHMSA performs 
extensive technical analysis on special permit applications and has 
granted special permits on the condition that operators will perform 
alternative measures to retain a consistent level of pipeline safety 
for the new class location throughout the life cycle of the pipeline. 
In 2004, PHMSA published guidance in the Federal Register that 
addressed the common conditions for granting class location change 
special permit requests. This guidance clarified PHMSA's process for 
granting a class location waiver that would allow operators to perform 
alternative risk-control activities based on integrity management (IM) 
concepts, rather than pipe replacement, pressure testing, or pressure 
reductions.\6\
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    \5\ The special permit process is outlined in Sec.  190.341 and 
is no different for waiving the class location regulations than for 
waiving any other requirements in the PSR.
    \6\ Public notices were published in Federal Register: 
``Pipeline Safety: Development of Class Location Change Waiver 
Guidelines,'' 69 FR 22115 (Apr. 23, 2004); and ``Pipeline Safety: 
Development of Class Location Change Waiver Criteria,'' 69 FR 38948 
(June 29, 2004). Additional guidance is provided online at: http://primis.phmsa.dot.gov/classloc/index.htm.
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    On January 3, 2012, Congress adopted the Pipeline Safety, 
Regulatory Certainty, and Job Creation Act of 2011 (2011 Pipeline 
Safety Act).\7\ Section 5 of that act required that PHMSA evaluate 
whether applying IM principles to areas outside of high consequence 
areas (HCA), with respect to gas transmission pipeline facilities, 
could possibly mitigate or eliminate the need for class location 
requirements.\8\ As stated in the resulting class location report 
titled ``Evaluation of Expanding Pipeline Integrity Management Beyond 
High-Consequence Areas and Whether Such Expansion Would Mitigate the 
Need for Gas Pipeline Class Location Requirements'' that was issued in 
2016 (2016 Class Location Report), the application of IM requirements 
to gas transmission pipelines outside of HCAs would not warrant the 
total elimination of class locations.\9\ However, PHMSA stated that it 
intended to consider whether adjustments were needed in the way that 
operators were required to implement certain requirements when class 
locations did change.
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    \7\ Pipeline Safety, Regulatory Certainty, and Job Creation Act 
of 2011; signed January 3, 2012; Public Law 112-90.
    \8\ Id. at sec. 5(a).
    \9\ See https://www.regulations.gov/document?D=PHMSA-2011-0023-0153.
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    On July 31, 2018, PHMSA published an advance notice of proposed 
rulemaking (ANPRM) in the Federal Register to seek feedback regarding 
the revision of the PSR applicable to the management of gas 
transmission pipeline segments where the class location has 
changed.\10\ Specifically, PHMSA requested comments regarding whether 
operators should have the option of performing certain risk-based IM 
activities in lieu of the current required activities (i.e., pipe 
replacement, pressure test, or pressure reduction) and whether those 
modifications could mitigate the public safety need for the existing 
class location requirements in this context. This ANPRM was initiated 
to honor the commitment made at the conclusion of the 2016 Class 
Location Report that PHMSA would study alternatives to the regulatory 
requirement for pipe replacement when class locations change and was 
also responsive to comments made to a 2017 DOT notice regarding 
regulatory review actions.\11\
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    \10\ ``Pipeline Safety: Class Location Change Requirements,'' 83 
FR 36861 (July 31, 2018).
    \11\ ``Notification of Regulatory Review,'' 82 FR 45750 (Oct. 2, 
2017).
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    Based on input in previous public meetings and workshops,\12\ the 
comments received on the ANPRM, the 2016 Class Location report, and a 
review of PHMSA's active special permits for Class 1 to Class 3 
location changes,\13\ PHMSA proposes to amend the class location change 
regulations for certain in-service gas transmission segments where the 
class location has changed from a Class 1 to a Class 3 to add an IM-
based alternative to the existing requirements. PHMSA is requesting 
input from the public on all aspects of this proposal, including 
whether the modification or elimination of the proposed pipe 
eligibility attributes or additional preventative and mitigative 
measures would provide an equivalent level of safety and maximize net 
benefits to society.
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    \12\ See Section II, D of this document titled, ``Class Location 
Studies, Public Workshop, Report, and Stakeholder Input.''
    \13\ As of May 1, 2019, PHMSA's 12 special permits for Class 1 
to Class 3 location changes apply to segments of pipe in the States 
of Alabama, Arizona, Colorado, Georgia, Kentucky, Louisiana, 
Michigan, Mississippi, New Jersey, New Mexico, New York, Ohio, 
Pennsylvania, Tennessee, Texas, West Virginia, and Wyoming.
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B. Summary of the Major Regulatory Provisions

    PHMSA is proposing an IM-based alternative to the existing class-
location-change requirements. The NPRM addresses two main topics 
pertaining to the IM alternative: (1) The criteria that pipe must meet 
to be eligible for the alternative, and (2) the additional, IM-based 
safety requirements necessary for using the alternative. Both aspects 
serve to protect public safety when pipeline operators apply the 
alternative approach.

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    The NPRM addresses segments that change from a Class 1 to a Class 3 
location after the publication of a final rule based on this proposed 
rulemaking and operate at 72 percent of specified minimum yield 
strength (SMYS) \14\ or less. PHMSA proposes that for segments that are 
eligible based on pipe attributes, operators choosing the IM 
alternative would adhere to documentation requirements, operations and 
maintenance (O&M) requirements, and other additional safety measures 
proposed in this rulemaking. Operators who do not meet the requirements 
of the proposed rule would need to follow the current regulatory 
requirements for class location changes or apply for a special permit.
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    \14\ SMYS is an indication of the minimum stress that a pipe may 
experience that will cause plastic, or permanent, deformation of the 
steel pipe.
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    Specifically, pipeline segments meeting the following conditions or 
having the following attributes would be ineligible for the IM 
alternative for managing class location changes:
     Bare pipe;
     Wrinkle bends;
     Missing material properties records;
     Certain historically problematic seam types; \15\
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    \15\ Problematic seam types include direct current (DC), low-
frequency electric resistance welded pipe (LF-ERW), electric flash-
welded (EFW) pipe, lap-welded pipe, and pipe seams with a 
longitudinal joint factor below 1.0 as defined in Sec.  192.113.
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     Body, seam, or girth-weld cracking; \16\
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    \16\ This cracking can include stress corrosion cracking and 
selective seam weld corrosion, which are cracking defects in the 
pipe body or weld seam. Cracks are undesired openings or separations 
in a normally rigid material, such as a pipe wall, and are 
detrimental to the capability of a pipeline to restrain pressure. 
Often, cracks are found only on the surface and do not penetrate the 
pipe wall. However, cracks that don't fully penetrate the pipe wall, 
if left unchecked, can propagate into a failure or a rupture and 
must be promptly repaired.
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     Pipe with poor external coating or with tape wraps or 
shrink sleeves;
     A leak or failure history within 5 miles of the segment; 
\17\
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    \17\ These would be leaks or failures reported to PHMSA via an 
incident report per part 191.
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     Pipe transporting gas that is not of suitable composition 
and quality for sale to gas distribution customers; and
     Pipe operated in accordance with Sec.  192.619 (c) or (d).
    PHMSA also proposes that a pipeline segment would be ineligible if 
it did not have a documented successful \18\ 8-hour, part 192, subpart 
J, pressure test to a minimum of 1.25 times MAOP. Pipeline segments 
that were previously ``uprated'' \19\ without a documented pressure 
test would also not be eligible unless the operator conducts a new 
pressure test.
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    \18\ A ``successful'' pressure test is one where the pipe does 
not rupture or leak because of the test. Part 192, subpart J, 
prescribes the minimum leak-test and strength-test requirements for 
pipelines.
    \19\ An ``uprate'' is where an operator increases the MAOP of 
its pipeline. To increase the pressure on its pipeline, an operator 
must comply with the minimum requirements prescribed in subpart K of 
part 192. An operator would still be subject to the leak-test and 
strength test requirements, including recordkeeping requirements, 
under part 192, subpart J.
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    These applicability criteria would help protect public safety by 
assuring that pipeline segments with known elevated risks that are 
changing from a Class 1 to a Class 3 location are pressure-tested, de-
rated to a lower MAOP, or replaced with new and stronger pipe, as 
required by the current regulations in Sec.  192.611. In most cases, 
this eligibility criteria prevents pipe that would be more susceptible 
to corrosion or cracking from using this NPRM alternative, and it also 
helps to ensure that operators can use the proper assessment and 
mitigation methods on pipeline segments that could cause great harm to 
the public based on their risk. PHMSA is concerned that, with the 
additional risk for corrosion and cracking many of these segments would 
have, anomalies might be able to grow to a failure size before the next 
assessment. Therefore, PHMSA has proposed these eligibility criteria as 
a matter of ensuring that pipe integrity can be maintained in Class 3 
locations where pipe designed to Class 1 standards remains in service. 
PHMSA discusses this in more detail later in this document and seeks 
comment on whether there is an alternative approach that would maximize 
net benefits to society while maintaining safety.
    Pipeline segments changing to a Class 4 location would not be 
eligible for the IM alternative under this proposal, but would rather 
be accommodated through PHMSA's current class location special permit 
process.\20\
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    \20\ PHMSA has neither included Class 4 locations in this 
proposed rule nor would it include such locations in any other NPRM 
without having first developed a unique set of conditions to 
maintain safety for multi-story buildings and applying them through 
the issuance of several special permits.
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    If a pipeline segment meets all eligibility criteria and the 
operator opts to follow the IM alternative, PHMSA proposes to require 
that the operator notify PHMSA of details of each segment that 
experienced a Class 1 to Class 3 location change 60 days prior to 
implementing the IM alternative.
    PHMSA is also proposing to modify the definition of an HCA to 
include these Class 1 to Class 3 location segments, which would then 
make these specific segments subject to all the requirements in subpart 
O, in addition to the more stringent requirements discussed in more 
detail below. When subpart O was developed and promulgated in 2003,\21\ 
PHMSA did not anticipate that operators would be able to demonstrate 
adequate pipeline integrity for pipe that was not designed for the 
class location in which it was located. Therefore, the regulations 
address any potential risk that would be involved when a class location 
changes by requiring that the pipeline operate at a lower pressure if 
an operator does not replace the pipeline segment or pressure test the 
segment. The proposal would allow operators to choose to follow IM 
requirements in subpart O and additional requirements for applicable 
segments, which include required in-line inspections (ILI), external 
pipeline coating, cathodic protection (CP),\22\ pipeline repair 
criteria to maintain MAOP with a Class 1 location 39 percent safety 
factor, usage of remote-controlled or automatic shutoff valves, and 
other additional preventive and mitigative (P&M) measures. PHMSA 
expects these measures to provide for an equivalent level of safety for 
the life of the pipeline when compared to pipe replacement.
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    \21\ ``Pipeline Safety: Pipeline Integrity Management in High 
Consequence Areas (Gas Transmission Pipelines),'' 68 FR 69778 (Dec. 
15, 2003).
    \22\ CP is a technique used to control or limit the corrosion of 
a pipeline's external metal surface by making it the cathode of an 
electrochemical cell. This treatment can be achieved with a special 
coating on the external surface of the pipeline along with an 
electrical system and anodes buried in the ground, or with a 
``sacrificial'' or galvanic metal acting as an anode. In those types 
of systems, the anode will corrode before the protected metal will.
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    More specifically, PHMSA is proposing that operators perform an 
initial integrity assessment using ILI tools within 24 months of the 
class location change, which would align with the current timeframe to 
either confirm or change the MAOP after a class location change. PHMSA 
would require operators to perform this ILI assessment on the entire 
pipeline segment that has experienced the change in class location, 
including from the nearest upstream ILI tool launcher to the nearest 
downstream ILI tool receiver.
    With respect to additional P&M measures beyond what are included in 
subpart O, PHMSA is proposing to require operators to do the following: 
Perform additional coating, interference, and corrosion surveys; 
remediate defined anomalies; install line-of-sight markers; install 
remote-control or automatic shutoff mainline valves; perform depth of 
cover surveys and

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remediation; clear shorted casings; perform additional right-of-way 
patrols and leakage surveys; and use a supervisory control and data 
acquisition (SCADA) system. These additional requirements would address 
aspects of pipeline integrity and public safety for which ILI 
assessments alone do not address, such as reducing the likelihood of 
third-party damage, detecting and mitigating conditions that can 
accelerate corrosion growth, and terminating gas flow from ruptures 
faster than would be required under existing regulations.
    Operators would also be required to keep documentation for all 
assessments, surveys, and any other required actions they perform in 
meeting the proposed requirements. PHMSA intends for this class 
location management option, when performed in conjunction with the 
requirements of subpart O, to provide a consistent-or-higher level of 
safety for the life of the pipeline if the operator chooses not to 
replace the pipe.

C. Costs and Benefits

    Consistent with Executive Order 12866, PHMSA has prepared an 
assessment of the benefits and costs of this proposed rule, as well as 
reasonable alternatives. The estimated cost savings of this proposal 
are due to avoided pipe replacement of segments for which operators 
employ the proposed IM alternative. In the Preliminary Regulatory 
Impact Analysis (PRIA) posted on the public docket, PHMSA presented two 
estimates of the number of miles that may change from a Class 1 to a 
Class 3 location each year from 2019 to 2039 and analyzed them as two 
separate scenarios. Scenario 1 is based on an estimate of 78 miles per 
year, which is the average result from PHMSA's annual estimates based 
on historical annual report data from 2010 to 2017. Scenario 2 is based 
on the median of PHMSA's annual estimates, which is 118 miles. PHMSA 
estimated the cost savings of the proposed rule by estimating the rate 
and unit cost for the currently available class location change 
compliance methods, the unit costs of complying with the special permit 
program, and the mix of consequence classifications among the affected 
segments. PHMSA assumes that this proposed rule would cause operators 
to replace pipe less often when a class location changes from Class 1 
to Class 3, as they would choose to use the IM alternative of this 
method where feasible. PHMSA estimated the costs of the IM alternative 
compared to the costs of pipe replacement against the estimated mileage 
changing from a Class 1 location to a Class 3 location per year. As 
such, PHMSA estimates the annual cost savings of the rule to be 
approximately $55 million for scenario 1, and $86 million for scenario 
2, both calculated at a 7 percent discount rate.

II. Background

A. Class Location History and Purpose

    The concept of class locations pre-dates the Federal regulation of 
gas transmission pipelines and was an early method of differentiating 
areas along natural gas transmission pipelines based on the potential 
consequence of a hypothetical pipeline accident. The first class 
location definitions were incorporated into the PSR on August 19, 1970, 
and were derived from the American Society of Mechanical Engineers 
(ASME) B31.8 designations that were included in the American Standards 
Association B31.8-1968 version of the ``Gas Transmission and 
Distribution Pipeline Systems'' standard, which eventually became ASME 
B31.8, ``Gas Transmission and Distribution Pipeline Systems.'' The 
definitions for class locations that PHMSA codified maintained the 
original ASME B31.8 characterizations for Class 1 through Class 3 
locations and added a new Class 4 location definition. These original 
class location definitions, with some slight modifications, are still 
applied today.
    PHMSA uses class locations to provide safety margins and standards 
that are commensurate with the potential consequence of a pipeline 
failure based on the surrounding population. A pipeline's class 
location is based on the number of buildings or dwellings for human 
occupancy in the surrounding area.
    Pipeline class locations for onshore gas pipelines are determined 
using the concept of a ``sliding mile,'' which is a unit of measurement 
that is 1 mile in length, extending 220 yards on either side of the 
centerline of a pipeline, and moves along the pipeline. The number of 
buildings within this sliding mile at any point during the mile's 
movement determines the class location for the entire mile of pipeline 
that the sliding mile moves along.\23\
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    \23\ For the purposes of this rulemaking, a ``building'' may be 
interchangeably referred to as a ``home,'' a ``house,'' or a 
``dwelling,'' all of which refer to a structure intended for human 
occupancy, whether it is used as a residence, for business, or for 
another purpose.
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    A Class 1 location is a class location unit along a continuous mile 
containing 10 or fewer buildings intended for human occupancy or is an 
offshore area; a Class 2 location is a class location unit along a 
continuous mile containing 11 to 45 buildings intended for human 
occupancy; and a Class 3 location is a class location unit along a 
continuous mile containing 46 or more buildings intended for human 
occupancy, or is within 100 yards of a building or place of public 
assembly.\24\ Class 4 locations exist where buildings with four or more 
stories above ground are prevalent. Whenever a pipeline segment has 
multiple class locations, the higher-numbered class location applies to 
the entire segment.
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    \24\ Under Sec.  192.5, a location is Class 3 if it has a 
building or a small, well-defined outside area (including 
playgrounds, recreation areas, and outdoor theaters) that is 
occupied by 20 or more persons at least 5 days a week for 10 weeks 
in any 12-month period. The days and weeks need not be consecutive.
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    Potential consequences of personal injury and property damage 
resulting from incidents such as a leak- or rupture-type failure, 
increase in a more densely populated area. In addition, an increasing 
population around a pipeline amplifies the probability of an incident 
occurring due to additional external force stresses, corrosion, 
interference currents, loss of pipeline soil cover, damage from third 
parties, and other factors.
    Design factors \25\ are used along with pipe attributes in 
engineering calculations to determine the required design pressure and 
MAOP of each steel pipeline segment. To decrease operational hoop 
stresses \26\ in areas of higher consequence, these class location-
based design factors (i.e., MAOP derating factors) \27\ provide a 
safety margin and help ensure the pipeline is operated below 100 
percent of SMYS. As specified in Sec.  192.105, a pipeline's design 
pressure is determined using Barlow's Formula: P = (2St/D) x F x E x T, 
where P is the design pressure, S is the pipe's yield strength, t is 
the wall thickness of the pipe, D is the outside diameter of the pipe, 
F is the design factor specific to the class location, E is the 
longitudinal joint factor,\28\ and T is the temperature

[[Page 65146]]

derating factor.\29\ To illustrate how class location design factors 
influence the MAOP of a pipeline, consider a 1000 psig pipeline (1.0 
design factor) with the same operating parameters (diameter, wall 
thickness, yield strength, seam type, and temperature) but in different 
class locations. The pipeline MAOPs would be as follows:
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    \25\ Design factors, which are used to calculate the design 
pressure for steel pipe in Sec.  192.105(a), are listed in Sec.  
192.111. Class 1 locations have a 0.72 design factor, Class 2 
locations have a 0.60 factor, Class 3 locations have a 0.50 factor, 
and Class 4 locations have a 0.40 design factor.
    \26\ ``Hoop stress'' is the stress in a pipe wall, acting 
circumferentially in a plane perpendicular to the longitudinal axis 
of the pipe, that is produced by the pressure of the product in the 
pipe. Hoop stress is calculated using Barlow's Formula, which is at 
Sec.  192.105. Hoop stresses are the same as design pressure, unless 
an outside force is acting on it. If hoop stress has the same safety 
factor as MAOP, then they are equal.
    \27\ MAOP determination and the required design factors for the 
class location can be found in Sec. Sec.  192.105, 192.111, and 
192.619.
    \28\ The longitudinal joint factor, based on the weld seam type 
of a pipeline, per this formula, has a limiting effect on the MAOP 
of the pipeline. While it is typically ``1.00'' and would not affect 
the calculation, certain types of furnace butt-welded pipe or pipe 
not manufactured to certain 49 CFR part 192-approved industry 
standards will have factors of 0.60 or 0.80, which will necessitate 
a reduction in design pressure. The longitudinal joint factors for 
steel pipe are listed at Sec.  192.113.
    \29\ The temperature derating factor ranges from 1.000 to 0.867 
depending on the operating temperature of the pipeline. Pipelines 
designed to operate at 250 degrees Fahrenheit and lower have a 
factor of 1.000, which does not affect the design pressure 
calculation. Pipelines designed to operate at higher temperatures, 
including up to 450 degrees Fahrenheit, have derating factors less 
than one, which lowers the design pressure of the pipeline. Steel 
pipe temperature derating factors are listed at Sec.  192.115.

 Class 1--design factor = 0.72, MAOP = 720 psig
 Class 2--design factor = 0.60, MAOP = 600 psig
 Class 3--design factor = 0.50, MAOP = 500 psig
 Class 4--design factor = 0.40, MAOP = 400 psig

    As natural gas transmission pipeline standards and regulations have 
evolved, the class location concept was incorporated into many other 
regulatory areas, including test pressures, mainline block valve 
spacing, pipeline design and construction requirements, and on-going 
O&M requirements. In all, the class location concept is incorporated 
throughout part 192.\30\
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    \30\ Specifically, Sec. Sec.  192.5, 192.8, 192.9, 192.65, 
192.105, 192.111, 192.150, 192.175, 192.179, 192.243, 192.327, 
192.485, 192.503, 192.505, 192.609, 192.611, 192.613, 192.619, 
192.620, 192.625, 192.705, 192.706, 192.707, 192.713, 192.903, 
192.933, and 192.935.
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    Modern pipeline inspection technology includes ILI and above-ground 
coating surveys. ILI technology uses devices that flow with the product 
in the pipeline and are colloquially known as ``smart pigs,'' which can 
measure and record irregularities in the pipe body and welds, including 
pipe wall loss (such as corrosion metal loss, gouges, scrapes, etc.), 
cracking, deformations, and dents.
    There are various types of ILI tools using different technologies 
that have distinct capabilities for detecting specific types of 
pipeline anomalies. However, in selecting the most suitable ILI tool, a 
pipeline operator must know the type of threats that are applicable to 
the pipeline segment. For example, a high-resolution magnetic flux 
leakage (HR-MFL) ILI tool can detect internal and external corrosion 
metal loss reliably but cannot accurately determine whether the 
pipeline has dents, deformations, or tight crack indications such as 
stress corrosion cracking \31\ or seam-weld cracks. A high-resolution 
deformation tool would be most appropriate for dents, whereas an 
electro-magnetic acoustic transducer (EMAT) tool would be the most 
appropriate for cracking.
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    \31\ A ``tight crack'' is a crack that is below 0.008 inches in 
width. Stress corrosion cracking is a form of corrosion that 
produces a marked loss of pipeline strength with little metal loss. 
The combined influence of pipeline stress and a corrosive medium can 
result in the formation of interlinking crack clusters that can grow 
until the pipe fails.
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    PHMSA first issued its IM regulations for gas transmission 
pipelines on December 15, 2003,\32\ in response to tragic gas pipeline 
incidents near Carlsbad, NM, in 2000,\33\ where 12 people were killed; 
and in Edison, NJ, in 1994, where 8 buildings were destroyed and 
approximately 1,500 residents were evacuated.\34\ The IM regulations 
provided a definition for HCA and required operators to assess the 
condition of pipelines periodically in these areas and make any 
necessary repairs within defined timeframes.
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    \32\ 68 FR at 69778.
    \33\ NTSB, Pipeline Accident Report: Natural Gas Pipeline 
Rupture and Fire Near Carlsbad, New Mexico August 19, 2000, PAR-03-
01, adopted on February 11, 2003.
    \34\ NTSB, Pipeline Accident Report: Texas Eastern Transmission 
Corporation Natural Gas Pipeline Explosion and Fire, Edison, New 
Jersey; March 23, 1994; PAR-95-01, adopted on January 18, 1995.
---------------------------------------------------------------------------

    Prior to the recent publication of the ``Pipeline Safety: Safety of 
Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of 
Assessment Requirements, and Other Related Amendments'' final rule on 
October 1, 2019 (2019 Gas Transmission Final Rule),\35\ operators were 
not required to assess or perform IM functions on pipeline segments 
outside of HCAs. With the publication of that rule, operators of 
onshore steel transmission pipeline segments with an MAOP of greater 
than or equal to 30 percent of SMYS and that are located in a Class 3 
locations, a Class 4 locations, or a ``moderate consequence area'' as 
defined in Sec.  192.3 where the segment can accommodate inspection by 
means of an instrumented ILI tool, must assess their pipelines 
periodically, but on a less-frequent basis than those pipelines in 
HCAs.\36\ The 2019 Gas Transmission Final Rule also requires operators 
to have a continuing surveillance program for all pipeline segments and 
take appropriate action to maintain safety concerning changes in class 
location, among other things.
---------------------------------------------------------------------------

    \35\ 84 FR 52180.
    \36\ 49 CFR 192.710.
---------------------------------------------------------------------------

B. Changes in Class Location Due to Population Growth

    When the population around a pipeline increases and causes the 
class location to increase, the numeric value of the design factor 
decreases, which translates, as detailed in the formula in Sec.  
192.105, into a lower MAOP for the pipeline. As the dwellings within 
the class location unit grow such that a Class 1 location becomes a 
Class 3 location, the corresponding difference in design factor, from a 
0.72 to 0.5, equates to an approximate 30 percent reduction in MAOP.
    If a class location increases and the current MAOP is not 
commensurate with the MAOP for the newly determined class location, 
besides applying for a special permit, the existing regulations require 
that the operator:
    (1) Reduce the pipeline's MAOP to reduce stress levels in the pipe;
    (2) replace the existing pipe with pipe that has more wall 
thickness or higher yield strength to operate at a lower operating 
stress at the same MAOP; or
    (3) conduct a pressure test (conforming to subpart J) at the higher 
test pressure needed to meet requirements for the newly determined 
class location if the pipeline segment has not previously been tested, 
for a minimum of 8 hours, at the higher pressure.\37\
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    \37\ See Sec.  192.611, as appropriate, for one-class changes 
(e.g., Class 1 to 2 or Class 2 to 3 or Class 3 to 4). As an example, 
for a Class 1 to Class 2 location change, the pipeline segment would 
require a pressure test to 1.25 times the MAOP for at least 8 hours. 
Following a successful pressure test, the pipeline segment would not 
need to be replaced with new pipe, but the existing design factor of 
0.72 for a Class 1 location would be acceptable for a Class 2 
location. The pressure test must meet the documentation requirements 
of Sec.  192.517.
---------------------------------------------------------------------------

    In accordance with those options, depending on the pipeline's test 
pressure and whether it meets the requirements in Sec. Sec.  192.609 
and 192.611, the operator can base the pipeline's MAOP on a specified 
design factor multiplied by the test pressure for the new class 
location as long as the corresponding hoop stress does not exceed 
certain percentages of the SMYS of the pipe and as long as the pipeline 
has been tested for a period of 8 hours or longer per Sec.  
192.611(a)(1).\38\ This

[[Page 65147]]

approach is practical for situations of a ``one-class bump'' where a 
pipeline segment's class location changes from Class 1 to a Class 2, a 
Class 2 to a Class 3, or a Class 3 to a Class 4.\39\ However, when 
population growth occurs to a degree that results in a class location 
change from a Class 1 location to a Class 3 location, the existing 
options of pressure testing or reducing operating pressure can be 
technically or operationally prohibitive for meeting contractual gas 
flow volume obligations.\40\ If an operator cannot pressure test or 
reduce operating pressure, the only options remaining per the existing 
regulations are to replace the pipe with higher-strength pipe by 
installing pipe with either greater wall thickness or higher steel 
grade or apply for a special permit.
---------------------------------------------------------------------------

    \38\ Specifically, if the applicable segment has been 
hydrostatically tested for a period of 8 hours or longer, the MAOP 
is 0.8 times the test pressure in Class 2 locations, 0.667 times the 
test pressure in Class 3 locations, or 0.555 times the test pressure 
in Class 4 locations. The corresponding hoop stress may not exceed 
72 percent of SMYS of the pipe in Class 2 locations, 60 percent of 
SMYS in Class 3 locations, or 50 percent of SMYS in Class 4 
locations.
    \39\ Based on the original in-place design of a pipeline, an 
operator can only perform a single one-class bump in a pipeline's 
lifetime. Pipelines constructed to the standards of lower class 
locations (i.e., Class 1) cannot meet more rigorous testing 
requirements when class locations continue to increase, which 
eventually requires operators to replace the pipe or apply to PHMSA 
for a special permit.
    \40\ See the Preliminary Regulatory Impact Assessment (PRIA) for 
more details.
---------------------------------------------------------------------------

    The class location regulations, when they were promulgated in 1970, 
required operators to replace pipeline segments when population growth 
resulted in a class location change to ensure that the safety margin 
was commensurate with the new class location. At that time, the 
pipeline industry did not have the technology available to determine 
the in-situ \41\ material condition of their pipelines, and it was 
unlikely that existing pipe could achieve a similar safety margin as 
replaced pipe per the regulations.
---------------------------------------------------------------------------

    \41\ In other words, the condition of their pipelines as they 
existed in place in the ground.
---------------------------------------------------------------------------

    Following the implementation of the IM regulations in 2003, and 
throughout the development of the 2019 Gas Transmission Final Rule, 
pipeline operators and industry trade associations requested that PHMSA 
provide operators with an additional alternative to managing class 
location changes: One that would use modern IM principles to assess the 
pipelines in question and help ensure that their integrity is 
maintained. PHMSA is proposing and requesting comments on a defined IM 
alternative that operators can use to manage pipeline segments where 
the class location has changed from Class 1 to Class 3. PHMSA expects 
that the additional repair and monitoring criteria proposed in this 
rule would provide, for Class 1 pipe that is in a Class 3 location, 
safety for the life of the pipeline that would be equivalent to that 
provided by a pipeline designed to Class 3 standards. This NPRM would 
not allow operators to manage Class 1 to Class 4 or Class 2 to Class 4 
location changes in the same manner. This restriction is because Class 
4 locations are so densely populated that the measures that could be 
provided through an IM alternative on thinner-walled pipe designed for 
a Class 2 location would not give people a chance to evacuate from a 
nearby rupture. PHMSA does not believe, at this time, that there are 
additional, feasible measures that can be implemented, on top of the 
ones proposed in this NPRM for Class 1 to Class 3 location changes, 
that can mitigate such risk and stand in for thicker-walled or 
stronger, higher grade pipe designed to Class 4 standards. PHMSA seeks 
comment on this current understanding.

C. Class Location Change Special Permits

    As discussed above, in the absence of alternative regulations such 
as those proposed in this notice, some operators have applied to PHMSA 
for special permits to manage class location changes without replacing 
pipe or reducing the operating pressure. A special permit is an order 
issued under Sec.  190.341 that waives or modifies compliance with 
regulatory requirements if the pipeline operator can demonstrate a 
need, and PHMSA determines that granting the special permit or granting 
the special permit with conditions attached would be consistent with 
pipeline safety. Upon receipt of such a request, PHMSA publishes a 
notice and request for comment in the Federal Register for each special 
permit application received and tracks issued, denied, and expired 
special permits on its website.\42\
---------------------------------------------------------------------------

    \42\ https://www.phmsa.dot.gov/pipeline/special-permits-state-waivers/special-permits-and-state-waivers-overview.
---------------------------------------------------------------------------

    In 2004, PHMSA published the typical considerations for class 
location change special permit requests in a Federal Register notice 
titled ``Pipeline Safety: Development of Class Location Change Waiver 
Criteria'' (69 FR 38948; June 29, 2004; ``2004 Federal Register 
Notice''). These considerations were developed by adapting risk-based 
IM concepts. For each class location change special permit request, 
PHMSA reviews the information submitted by the operator, which includes 
a list of the proposed sites, pipeline attributes, prior assessment 
results and assessment schedules, incident and leak history, prior 
repairs, damage prevention initiatives, prior safety-related condition 
reports, a summary of integrity threats, and the operator's risk-
control activities. PHMSA then approves class location change special 
permits on the condition that operators implement integrity assessments 
and other P&M measures, which go beyond the regulatory 
requirements.\43\ The additional monitoring and maintenance 
requirements PHMSA prescribes through this process help to ensure the 
integrity of the pipe to maintain a level of safety consistent with 
lowering the MAOP, conducting a new pressure test, or installing 
thicker-walled or higher-grade pipe. The class location change special 
permits that PHMSA has granted have allowed operators to continue 
operating the pipeline segments identified under the special permits at 
their current MAOP based on the previous class locations. In order to 
issue such a special permit, PHMSA must determine that the present 
class location change special permit conditions and operator 
implementation of these conditions are consistent with public safety 
and demonstrate the current application of class location change 
management. As such, they can provide a basis for the consideration of 
this proposed alternative.
---------------------------------------------------------------------------

    \43\ Special permit conditions are implemented to mitigate the 
causes of gas transmission incidents and are based on the type of 
threats pertinent to the pipeline. The conditions are generally more 
heavily weighted on identifying material, coating, and CP issues; 
pipe wall loss; pipe and weld cracking; depth of pipe cover; third 
party damage prevention; marking of the pipeline and pipeline right-
of-way patrols; pressure tests and documentation; data integration 
of integrity issues; and reassessment intervals. Examples of PHMSA's 
class location special permit conditions can be found at: https://primis.phmsa.dot.gov/classloc/docs/SpecialPermit_ExampleClassLocSP_Conditions_090112_draft1.pdf, and 
more information about PHMSA's special permit process for class 
location changes can be found at: https://primis.phmsa.dot.gov/classloc/documents.htm.
---------------------------------------------------------------------------

    Since 2001, PHMSA has received over 30 applications from operators 
for waivers from the class location requirements in Sec.  192.611 for 
pipeline segments changing from a Class 1 to a Class 3 location. PHMSA 
has approved approximately half of these applications and issued the 
corresponding special permits, with over 10 currently in effect.\44\ 
The pipeline segments for

[[Page 65148]]

which PHMSA has granted special permits cover a range of diameters from 
16 to 36 inches. Most the class location change special permits PHMSA 
has issued have been implemented effectively by operators and 
subsequently renewed; PHMSA notes that, to date, no leaks or failures 
have occurred on the approximately 100 miles of current class location 
change special permit pipeline segments.
---------------------------------------------------------------------------

    \44\ PHMSA has rejected class location change special permits 
due to the presence of pipe conditions, including cracking, major 
corrosion, or other systemic issues, that are not easy to address 
via the special permit process. PHMSA considers the age and 
manufacturing process of the pipe and the construction processes 
used as well. Additionally, some operators have withdrawn special 
permit applications before being denied.
---------------------------------------------------------------------------

i. Class Location Change Special Permit Eligibility Requirements
    Most of the Class 1 to Class 3 class location change special permit 
requests that PHMSA receives are for older pipeline segments built with 
lower-strength pipe, based upon its design in accordance with 49 CFR 
192.105 for a Class 1 location, that operators would likely not be able 
to pressure test to the 1.5 times MAOP test pressure without failure 
required for Class 3 locations.\45\ Such pipe tends to be higher-risk 
due to the materials and construction techniques available at the time 
of the pipe's installation, so each pipeline segment must meet several 
``threshold conditions'' before PHMSA grants a special permit. These 
conditions include a review of the pipe's seam type, field girth 
welds,\46\ coating type, depth of cover,\47\ materials 
documentation,\48\ pressure testing duration and minimum test 
pressure,\49\ defect and corrosion history, repair criteria used,\50\ 
CP, and the quality of gas transported and its effect on internal 
corrosion.\51\
---------------------------------------------------------------------------

    \45\ Some gas transmission infrastructure was installed before 
the 1970s, using techniques that can contain latent defects. For 
example, pipe manufactured using low-frequency electric resistance 
welding or lap-welding techniques is susceptible to seam failure.
    \46\ Girth welds are made where two pipes are joined along their 
circumferences. PHMSA reviews whether operators have performed non-
destructive examinations of any girth welds and what percentage of 
the welds have been examined.
    \47\ The requirements for the depth of cover over a buried 
pipeline are at Sec.  192.327, and they specify how much soil or 
consolidated rock must cover a pipeline at a given class location. 
PHMSA reviews whether there is less than 30 inches of cover over the 
pipeline and whether the pipe needs to be lowered or if additional 
mitigation measures need to be performed.
    \48\ PHMSA reviews whether the operator has good material 
physical property records of the pipeline segment and whether 
operators have documentation for wall thickness, seam types, etc.
    \49\ The pressure testing requirements for pipelines are in 
subpart J (Sec. Sec.  192.501-192.517). PHMSA reviews whether 
operators have a proof test to confirm they have records for a 
safety factor above the MAOP (an increase of 25 percent).
    \50\ PHMSA reviews whether the repair criteria an operator uses 
has a required maximum defect depth and a pressure rating 39 percent 
above the MAOP.
    \51\ PHMSA reviews whether the gas has a high percentage of 
carbon dioxide (approximately 3 percent), or hydrogen sulfide (16 
parts per million) and does not have water vapor above 7 lbs. per 
million. In PHMSA's experience, these thresholds are consistent with 
typical FERC gas tariffs for individual companies.
---------------------------------------------------------------------------

    PHMSA also considers O&M practices and pipe attributes, and 
requires documentation when evaluating pipeline segment for a class 
location change special permit. For example, PHMSA does not grant class 
location special permits for pipeline segments with bare pipe or pipe 
containing wrinkle bends, or for pipe operating above 72 percent 
SMYS.\52\ As a part of the special permit application process, 
operators must have or obtain documentation detailing the pipeline 
segment's diameter, wall thickness, grade, seam type, yield strength, 
tensile strength, and coating type. Finally, PHMSA considers the 
history of an operator's compliance with PSR when reviewing special 
permit applications.
---------------------------------------------------------------------------

    \52\ Pipeline segments with these attributes do not meet the 
current part 192 standards for construction of transmission 
pipelines, regardless of the class location they are in. PHMSA 
approves special-permit applications based on the applicant's pipe 
being considered sound in accordance with current standards and 
ensuring through additional measures that an operator can manage the 
pipe to a consistent level of safety.
---------------------------------------------------------------------------

ii. Special Permit Compliance Conditions
    The conditions PHMSA imposes in class location change special 
permits apply to the ``special permit segment,'' which is the specific 
pipeline segment where the class location change has occurred. In class 
location change special permits, PHMSA has also required operators to 
assess for threats up to 25 miles on either side of the special permit 
segment in an area known as the ``special permit inspection area.'' 
\53\ The purpose of considering this larger special permit inspection 
area is to provide a means by which threats and pipe defects in nearby 
pipe can be discovered and remediated. In addition, potential incident 
causes that could affect the special permit segment can be identified 
and corrected, thus helping find and fix problems in the special permit 
segment before pipeline integrity is compromised.
---------------------------------------------------------------------------

    \53\ In the class location change special permits, PHMSA 
required operators assess up to 25 miles on both sides of the 
special permit segment as a proxy for the nearest ILI tool launcher 
and receiver stations. As discussed later in this document, PHMSA is 
proposing to make explicit the requirement for operators to assess 
to ILI tool launcher and receiver stations in this NPRM.
---------------------------------------------------------------------------

    PHMSA's typical class location change special permit conditions 
require an operator to incorporate the identified segment(s) into its 
integrity management program (IMP). An IMP, as detailed in subpart O of 
part 192, requires operators to perform ongoing risk analyses, perform 
integrity assessments to identify and analyze applicable threats to the 
pipeline, repair any anomalies, and implement appropriate P&M measures 
to ensure the integrity of the pipeline in HCAs (typically where there 
are significant populations). PHMSA's enforcement of operator IMPs 
holds operators accountable if they fail to take adequate steps under 
IM to mitigate the risks for their applicable pipeline segments.
    Another condition included in class location change special permits 
is that each applicable special permit segment must be operated at or 
below its existing MAOP; this operating pressure is higher than the 
pressure reduction that would be required under the current class 
location change requirements in Sec.  192.611. As a part of complying 
with the special permit conditions, and consistent with IM principles, 
PHMSA also requires operators to address issues pertaining to pipe 
coating quality, selective seam weld corrosion, stress corrosion 
cracking (SCC), and the effects of any long-term pipeline system flow 
reversals. In addition, PHMSA often requires operators to perform 
additional CP and corrosion-control measures on special permit 
segments, including performing coating condition surveys, coating 
remediation, and upgrading CP systems.
    While PHMSA has the authority to modify special permit conditions 
in the interest of public safety, PHMSA has not significantly changed 
the original conditions imposed in the class location change special 
permits, in most cases, when operators apply to renew them. In a few 
cases in the early 2000s, class location SPs did not have required 
periodic reassessment intervals, pipe remediation, coating assessment, 
or other integrity requirements. PHMSA has added additional safety 
requirements when the special permits have been renewed. These early 
special permits were granted prior to the development of the class 
location change waiver guidelines and criteria in 2004. These public 
notices outlined the special permit attributes that PHMSA would review 
and gave an overview of the safety and integrity measures that PHMSA 
would require in future special permit conditions. In cases when 
certain changes have been made, they are a result of lessons learned 
during the special permit process. For example, when PHMSA first 
established the special permit process for class location changes in 
2004, the special permits had no expiration dates. In 2008, the agency 
chose to impose an expiration date of 5 years for all new class 
location change special permits. At the time, PHMSA

[[Page 65149]]

felt that a 5-year expiration limit would serve as an appropriate 
frequency of review of the conditions and their impact on public 
safety. Based on PHMSA's experience over the past 15 years of 
monitoring these special permits and through safety reviews during the 
periodic special permit renewal process, PHMSA has extended the 
expiration date of its class location change special permits to 10 
years. This 10-year timeframe allows an operator to conduct every 
required IM assessment and re-assessment \54\ prior to submitting a 
renewal request to PHMSA for an updated special permit.\55\
---------------------------------------------------------------------------

    \54\ See 49 CFR 192.939.
    \55\ In all special permits, PHMSA reserves the right to revoke 
the permit (see Sec.  190.341) before the set expiration date and 
order compliance with the regulations if PHMSA finds the operator is 
not complying with the provisions or if PHMSA discovers a safety 
condition on the pipeline.
---------------------------------------------------------------------------

D. Class Location Studies, Public Workshop, Report, and Stakeholder 
Input

    Prior to this NPRM, PHMSA considered extensive input from various 
stakeholders on the class location change regulations, various other 
alternatives, and safety impacts. This feedback was gathered through 
the public comment process via a Notice of Inquiry in 2013,\56\ public 
meetings in 2014, comments on the class location report and gas 
transmission NPRM in 2016, and comments to a DOT notice of regulatory 
review in 2017.\57\
---------------------------------------------------------------------------

    \56\ ``Pipeline Safety: Class Location Requirements,'' 78 FR 
46560 (Aug. 1, 2013).
    \57\ ``Notification of Regulatory Review,'' 82 FR 45750 (Oct. 2, 
2017).
---------------------------------------------------------------------------

i. Section 5 of the Pipeline Safety Act of 2011
    On January 3, 2012, Congress enacted the 2011 Pipeline Safety Act. 
Section 5 of that act required PHMSA to evaluate, with respect to gas 
transmission pipeline facilities, whether the potential application of 
IM program requirements, or elements thereof, to additional areas 
outside of HCAs would mitigate the need for class location 
requirements. Per the mandate, PHMSA reported the findings of this 
evaluation to Congress in 2016, as discussed below. The 2011 Pipeline 
Safety Act authorized PHMSA to issue regulations pursuant to the 
findings of the report. As discussed below, PHMSA issued an NPRM in 
2016 and a subsequent final rule in 2019 that addressed this mandate.
ii. 2013 Notice of Inquiry: Class Location Requirements
    On August 1, 2013, PHMSA issued a Notice of Inquiry soliciting 
comments on whether expanding IM requirements would mitigate the need 
for class locations per the section 5 mandate of the 2011 Pipeline 
Safety Act. The notice discussed several topics, including whether 
class locations should be eliminated entirely, whether a single design 
factor could be used in all situations, whether design factors should 
be increased for higher class locations, and whether pipelines without 
complete material properties records should be allowed to use a single 
design factor if class locations were eliminated.
    There was broad consensus among PHMSA stakeholders \58\ that 
entirely eliminating class locations would not lead to pipeline safety 
improvement. Further, commenters noted that establishing a single 
design factor to replace class location designations might be too 
complicated to implement. Many commenters noted that any changes in 
class location requirements would impact not only the classifications 
of many pipelines but would also possibly lead to several adverse 
unintended consequences \59\ related to compliance with 49 CFR part 
192, as the class location requirements are referenced or built upon 
throughout the natural gas regulations. Several industry trade groups 
made suggestions for changing the class location regulations--
specifically for using IM to manage pipeline segments where the 
operator had not replaced, pressure tested, or reduced the pressure of 
the pipeline segment. These suggestions were developed further through 
subsequent discussions at PHMSA's Gas Pipeline Advisory Committee 
(GPAC) meetings and at public workshops as described more fully below.
---------------------------------------------------------------------------

    \58\ Approximately 30 submissions were received from a wide 
range of stakeholders, including, but not limited to: Operators, 
trade organizations (Interstate Natural Gas Association of America, 
American Public Gas Association, American Petroleum Institute, 
American Gas Association), the Pipeline Safety Trust public interest 
group, the National Association of Pipeline Safety Representatives 
comprised of State pipeline safety regulators, and individual 
citizens. The submissions can be reviewed at https://www.regulations.gov/docket?D=PHMSA-2013-0161.
    \59\ API/AEPC explained that the elimination of class locations 
would preclude the ability to determine the regulatory status of 
gathering lines. See API's November 1, 2013, comment at 3, https://www.regulations.gov/document?D=PHMSA-2013-0161-0025.
---------------------------------------------------------------------------

iii. 2014 Pipeline Advisory Committee Meeting, Class Location Workshop, 
and Subsequent Comments
    On February 25, 2014, PHMSA hosted a joint meeting of the Gas and 
Liquid Pipeline Advisory Committees.\60\ At that meeting, PHMSA updated 
the committees on its activities regarding section 5 of the 2011 
Pipeline Safety Act, and committee members and participating members of 
the public provided their comments. During the meeting, the Interstate 
Natural Gas Association of America (INGAA) reinforced its comments in 
response to the 2013 Notice of Inquiry, noting that the original class 
location definitions in ASME B31.8 were intended to provide an 
increased margin of safety for higher-density population areas and 
stating that IM was a better risk-management tool than class locations. 
INGAA reported that its members intended to perform elements of IM on 
pipelines outside of HCAs.\61\
---------------------------------------------------------------------------

    \60\ The Pipeline Advisory Committees are statutorily mandated 
advisory committees that advise PHMSA on proposed safety standards, 
risk assessments, and safety policies for natural gas and hazardous 
liquid pipelines (49 U.S.C. 60115). These Committees were 
established under the Federal Advisory Committee Act (Pub. L. 92-
463, 5 U.S.C. app. 2) and the Federal Pipeline Safety Statutes (49 
U.S.C. 60101-60141, 60301-60302). Each committee consists of 15 
members, with membership divided among Federal and State agency 
representatives, the regulated industry, and the public.
    \61\ Per a 2013 presentation, INGAA states that it will strive 
to apply IM principles to the entire transmission systems operated 
by INGAA members, extending and consistently applying the program to 
the following: (1) 90 percent of the population in the vicinity of 
pipelines using IM principles, by 2012; (2) 90 percent of the 
population in the vicinity of pipelines using ASME B31.8S, by 2020; 
(3) 100 percent of the population in the vicinity of nearby 
pipelines using IM principles, by 2030; and (4) the remaining 20 
percent of pipeline mileage with no surrounding population using IM 
principles, after 2030. https://www.ingaa.org/File.aspx?id=20899&v=a0233b08.
---------------------------------------------------------------------------

    On April 16, 2014, PHMSA sponsored a workshop on class locations to 
solicit comments on whether the application of IM program requirements 
beyond HCAs would mitigate the need for gas pipeline class location 
requirements. Representatives from PHMSA, the National Energy Board of 
Canada, the National Association of Pipeline Safety Representatives 
(NAPSR), pipeline operators, industry groups, the Pipeline Safety Trust 
(PST), and public interest groups gave presentations.\62\
---------------------------------------------------------------------------

    \62\ Meeting presentations are available online at: http://primis.phmsa.dot.gov/meetings/MtgHome.mtg?mtg=95.
---------------------------------------------------------------------------

    During the workshop, INGAA alleged that the current class location 
regulations can result in the replacement of pipeline segments that do 
not warrant replacement and suggested that the special permit process 
for class location changes be embedded into part 192. Ameren Illinois, 
a member of the American Gas Association (AGA), noted that applying the 
current class location change requirements can cost more than $1 
million for each Class 1 to Class 3

[[Page 65150]]

location change. Therefore, AGA suggested eliminating the special 
permit process for class location changes and incorporating the 
specific requirements for special permits into 49 CFR part 192 as part 
of the regulations. AGA recommended two alternative approaches. The 
first would allow operators to continue to implement the class location 
approach as it exists and apply for special permits, if needed. The 
second would allow operators to implement a risk-based approach using 
additional IM actions.
    Accufacts and the PST pointed out how deeply the concept of class 
locations is embedded in part 192 and stated that IM requirements and 
class locations overlap in densely populated areas to provide a 
redundant, but necessary, safety regime. The PST also suggested that, 
in time, the older class location method potentially could be replaced 
with an IM method for regulation. However, the PST noted that incidents 
and other data suggest there is room for improvement in the IM 
regulations, as data shows higher incident rates in HCAs than in non-
HCAs and that pipe installed after 2010 has a higher incident rate than 
pipe installed a decade earlier. Similarly, Accufacts noted that the 
2010 Pacific Gas and Electric Company (PG&E) incident at San Bruno, CA, 
exposed weaknesses in the operator's IM program and demonstrated that 
the consequences resulting from the incident spread far beyond the 
expected potential impact radius (PIR).\63\ Therefore, Accufacts 
suggested that shifting the class location approach solely to an IM 
approach might decrease the protection of public safety.
---------------------------------------------------------------------------

    \63\ The PIR for the ruptured pipeline segment involved in the 
PG&E incident at San Bruno, CA, was calculated at 414 feet. However, 
the National Transportation Safety Board (NTSB), in its accident 
report (NTSB/PAR-11/01) noted that the subsequent fire damage 
extended to a radius of about 600 feet from the blast center.
---------------------------------------------------------------------------

    Following the workshop on class locations, INGAA submitted 
additional comments to the docket, stating that advancements in IM 
technology and processes have superseded the need for mandatory pipe 
replacement following a class location change. INGAA noted that in the 
past, it was logical to replace a pipeline when class locations changed 
because of the widespread belief that thicker pipe would take longer to 
corrode and would withstand greater external forces, such as damage 
from excavators, before failure. However, INGAA stated that given 
improvements in technology, advances in pipe quality, and ongoing 
regulatory processes such as IM, it believes that operators can 
mitigate most threats without the need for pipe replacement. Therefore, 
INGAA offered an approach to class location changes that would not 
require pipe replacement if pipeline segments met certain requirements 
that were in line with the current special permit conditions PHMSA 
established in the 2004 Federal Register Notice and that are currently 
in Class 1 to Class 3 location change special permits.\64\ 
Specifically, INGAA suggested that pipelines meeting a ``fitness for 
service'' standard in 18 categories could address potential safety 
concerns and preclude the need for pipe replacement.\65\
---------------------------------------------------------------------------

    \64\ See also http://primis.phmsa.dot.gov/classloc/index.htm.
    \65\ Those 18 categories were as follows: (1) Baseline 
Engineering and Record Assessments--Girth Weld Assessment, (2) 
Casing Assessment, (3) Pipe Seam Assessment, (4) Field Coating 
Assessment, (5) Cathodic Protection, (6) Interference Currents 
Control, (7) Close Interval Survey (CIS), (8) SCC Assessments, (9) 
In-line Inspection Assessments, (10) Metal Loss Anomaly Management, 
(11) Dent Anomaly Management, (12) Hard Spots Anomaly Management and 
Ongoing Requirements, (13) Integrity Management Program, (14) Root 
Cause Analysis for Failure or Leak, Line Markers, (15) Patrols, (16) 
Damage Prevention Best Practices, (17) Recordkeeping, and (18) 
Documentation.
---------------------------------------------------------------------------

iv. 2016 Class Location Report and Gas Transmission NPRM
    Based on the 2011 congressional mandate discussed above, PHMSA 
submitted a report to Congress in April 2016 titled, ``Evaluation of 
Expanding Pipeline Integrity Management Beyond High-Consequence Areas 
and Whether Such Expansion Would Mitigate the Need for Gas Pipeline 
Class Location Requirements,'' which outlined PHMSA's findings on the 
issue.\66\ The report also summarized operator comments and concerns 
regarding class location changes and subsequent pipe replacement, 
noting that operators said they could operate pipelines constructed in 
Class 1 locations that later change to Class 3 locations safely by 
using current IM practices.
---------------------------------------------------------------------------

    \66\ https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/news/55521/report-congress-evaluation-expanding-pipeline-imp-hcas-full.pdf.
---------------------------------------------------------------------------

    Concurrently, PHMSA published an NPRM titled, ``Safety of Gas 
Transmission and Gathering Pipelines'' (2016 Gas Transmission 
NPRM),\67\ in which PHMSA noted that the proposed application of IM 
program elements, such as assessment and remediation timeframes, beyond 
HCAs would not warrant the elimination of class locations.
---------------------------------------------------------------------------

    \67\ ``Pipeline Safety: Safety of Gas Transmission and Gathering 
Pipelines,'' 81 FR 20722 (Apr. 8, 2016).
---------------------------------------------------------------------------

    In those documents, PHMSA noted that class locations affect all gas 
transmission pipelines and are integral to determining the appropriate 
MAOP, design pressure, pipe wall thickness, valve spacing, HCA 
designation,\68\ O&M inspections, surveillance, and for evaluating 
anomalies for repair using ASME B31G \69\ and AGA Pipeline Research 
Committee Project PR 3-805 (RSTRENG).\70\ While IM measures are 
critical to risk mitigation and pipeline safety, the assessment and 
remediation of defects alone does not compensate for these other 
aspects of class locations adequately. Thus, as PHMSA outlined in the 
Class Location Report, it determined that the existing class location 
requirements are appropriate for maintaining pipeline safety and should 
be retained. Consequently, any revisions to the class location 
requirements would have to be forward-looking (i.e., applying to 
pipelines constructed after a certain effective date) and would have to 
provide commensurate safety as the existing regulatory regime.\71\
---------------------------------------------------------------------------

    \68\ Per Sec.  192.903, under Method 1, an HCA is an area 
defined as a Class 3 location, a Class 4 location, any area in a 
Class 1 or Class 2 location where the potential impact radius is 
greater than 660 feet and the area within the impact circle, which 
is defined by the potential impact radius for the pipeline, contains 
20 or more buildings intended for human occupancy, or any area in a 
Class 1 or Class 2 location where the potential impact circle 
contains an ``identified site.''
    \69\ ASME B31G, ``Manual for Determining the Remaining Strength 
of Corroded Pipelines,'' provides guidance for the evaluation of 
metal loss in pressurized pipelines and piping systems, and it 
applies to all pipelines and piping systems that are a part of the 
ASME B31 Code for Pressure Piping.
    \70\ For procedures to determine the remaining strength of 
pipelines, see Sec. Sec.  192.485(c) and 192.933(d). RSTRENG is a 
computer program developed to perform the procedure called ``A 
Modified Criterion for Evaluating the Remaining Strength of Corroded 
Pipe.'' This procedure was developed by Battelle Memorial Institute 
for the American Gas Association as an alternative to the ASME B31G 
procedures.
    \71\ In comments following the public workshop on class 
locations in 2014, INGAA noted that, after further analysis, it 
appears that applying the PIR method to existing pipelines may be 
unworkable, which is detailed in: https://www.regulations.gov/document?D=PHMSA-2013-0161-0037.
---------------------------------------------------------------------------

    As part of the continuing discussion on class location changes and 
subsequent pipe replacement, PHMSA summarized at the end of the 2016 
Class Location Report the concerns operators expressed regarding the 
cost of replacing pipe in locations that change from a Class 1 to a 
Class 3 location or a Class 2 to a Class 4 location. PHMSA noted in the 
2016 Class Location Report that, over the past decade, it had observed 
problems with pipe and fitting manufacturing quality, including low-

[[Page 65151]]

strength material; \72\ low-frequency and high-frequency electric 
resistance welded pipe seam quality; construction practices; welding 
and the non-destructive testing of welds; pipe denting; field coating 
practices; IM assessments and reassessment practices; \73\ and record 
documentation practices.\74\ Based on incidents resulting from these 
problems, PHMSA believes it is necessary to consider additional safety 
measures if allowing a ``two-class bump'' from a Class 1 location to a 
Class 3 location without requiring pipe replacement, especially for 
higher-pressure gas transmission pipelines.\75\
---------------------------------------------------------------------------

    \72\ PHMSA has documented low-strength pipe material issues in 
an advisory bulletin and the following website link: https://www.phmsa.dot.gov/pipeline/low-strength-pipe/low-strength-pipe-overview.
    \73\ IM and operational procedures and practices were issues in 
PG&E's incident at San Bruno, CA, in September 2010 and the Enbridge 
hazardous liquid pipeline rupture near Marshall, MI, in July 2010. 
PHMSA issued Advisory Bulletins: ``Pipeline Safety: Establishing 
Maximum Allowable Operating Pressure or Maximum Operating Pressure 
Using Record Evidence, and Integrity Management Risk Identification, 
Assessment, Prevention, and Mitigation,'' ADB-11-01, 76 FR 1504 
(Jan. 10, 2011) and ``Pipeline Safety: Using Meaningful Metrics in 
Conducting Integrity Management Program Evaluations,'' ADB-2012-10, 
77 FR 72435 (Dec. 5, 2012) to operators regarding IM meaningful 
metrics and assessments, which can be reviewed at: https://www.phmsa.dot.gov/regulations-fr/notices.
    \74\ PHMSA issued Advisory Bulletin ``Pipeline Safety: 
Verification of Records,'' ADB-12-06, 77 FR 26822 (May 7, 2012) 
concerning the documentation of MAOP, which can be reviewed at: 
https://www.phmsa.dot.gov/regulations-fr/notices. Also note PHMSA's 
Advisory Bulletin ``Pipeline Safety: Deactivation of Threats,'' ADB-
2017-01, 82 FR 14106 (Mar. 16, 2017).
    \75\ Section 192.611 allows a ``one-class bump'' based upon 
pressure test.
---------------------------------------------------------------------------

    PHMSA stated in the conclusion of the 2016 Class Location Report 
that it would further evaluate the feasibility and the appropriateness 
of alternatives to address issues pertaining to pipe replacement 
requirements, continue to reach out to and consider input from all 
stakeholders, and consider future rulemaking if a cost-effective and 
safety-focused approach to adjusting specific aspects of class location 
requirements could be developed to address the issues raised by 
pipeline operators. In doing so, PHMSA noted it would evaluate class-
location-change alternatives in the context of other issues it was 
addressing related to new construction quality and safety management 
systems and would also consider inspection findings, IM assessment 
results, and lessons learned from past incidents.
v. The AGA/API/INGAA Submission on Regulatory Reform--Proposal To 
Perform Integrity Management Measures In Lieu of Pipe Replacement When 
Class Locations Change
    On October 2, 2017, DOT issued a Notification of Regulatory Review 
seeking comment from the public on existing rules and other agency 
actions that would be good candidates for repeal, replacement, 
suspension, or modification. On November 9, 2017, AGA, API, and INGAA 
submitted joint comments to the corresponding docket.\76\ The joint 
comments asserted that gas transmission pipeline operators incur annual 
costs of $200 to $300 million nationwide replacing pipe solely to 
satisfy the class location change regulations. The joint commenters 
requested that PHMSA consider revising the current class location 
change regulations to include an alternative beyond pressure reduction, 
pressure testing, or pipe replacement, and provided a suggested 
approach for doing so.
---------------------------------------------------------------------------

    \76\ PHMSA notes that INGAA, individually, submitted nearly 
identical comments on the topic of class location on July 24, 2017 
in response to a previous request for input by DOT. ``Transportation 
Infrastructure: Notice of Review of Policy, Guidance, and 
Regulation,'' 82 FR 26734 (June 8, 2017).
---------------------------------------------------------------------------

    The joint commenters proposed an alternative approach for class 
location changes that focused on operators performing ``recurring [IM] 
assessments . . . [that] leverage advanced assessment technologies to 
determine whether [the] actual pipe condition warrants replacement'' in 
areas where the class location has changed. The commenters stated that 
such an approach would further promote IM processes and principles 
throughout the Nation's gas transmission pipeline network, improve 
economic efficiency by reducing a regulatory burden, and help fulfill 
the purposes of section 5 of the 2011 Pipeline Safety Act.
    The joint comments from AGA/API/INGAA asserted that the current 
alternatives to pipe replacement following a class location change do 
not reflect the substantial developments in IM processes, technologies, 
and regulations over the past 15 years since the initial IM regulations 
were first codified. The commenters suggested that advanced ILI 
technologies, such as HR-MFL tools, can assess the presence of 
corrosion and other potential defects, which can allow an operator to 
establish whether a pipeline segment needs remediation or replacement.
    The joint comments further noted that the 2016 Gas Transmission 
NPRM would expand IM assessments to newly defined ``moderate 
consequence areas,'' \77\ and that such an expansion would provide a 
framework for developing an alternative means of managing class 
location changes. The commenters supported the publication of the 
proposed provisions, as endorsed by the GPAC, to help provide such a 
framework. They suggested that the costs saved from avoiding pipe 
replacement using such an alternative could mitigate, to some degree, 
part of the costs of the 2016 Gas Transmission NPRM. In addition, they 
noted that the gas transmission NPRM contained several new provisions 
that would require operators to manage the integrity of their pipelines 
better by implementing more P&M measures to manage the threat of 
corrosion. The joint comments from AGA/API/INGAA stated that including 
such corrosion control measures as a part of a program for managing the 
integrity of pipeline segments, including ones that have experienced 
class location changes, would further justify the development of an IM-
focused alternative to class location changes.
---------------------------------------------------------------------------

    \77\ 81 FR at 20825, 20838.
---------------------------------------------------------------------------

    Based on those statements, AGA, API, and INGAA recommended that 
PHMSA develop an alternative approach to Sec.  192.611 that would 
leverage specific provisions in the 2016 Gas Transmission NPRM at its 
proposed Sec.  192.710 for assessing areas outside of HCAs and apply 
the proposed IM requirements at Sec.  192.921 to those assessed 
segments. Further, they suggested that operators could reconfirm a 
pipeline segment's MAOP in a changed class location if the pipeline 
segment in question did not have traceable, verifiable, and complete 
(TVC) records of a hydrostatic pressure test that supported the 
previous MAOP.

E. Class Location ANPRM

    On July 31, 2018, PHMSA published an ANPRM in the Federal Register 
seeking public comment on its existing class location requirements for 
natural gas transmission pipelines as they pertain to the actions that 
operators are required to take following class location changes due to 
population growth near pipelines.\78\
---------------------------------------------------------------------------

    \78\ 83 FR 36861.
---------------------------------------------------------------------------

    In the ANPRM, PHMSA requested comments and information to determine 
whether revisions should be made to the PSR regarding the current 
requirements that operators must meet when class locations change. 
PHMSA also welcomed any additional information that would be beneficial 
to the rulemaking process.

[[Page 65152]]

F. 2019 Gas Transmission Final Rule

    Following the publication of the 2016 Gas Transmission NPRM, PHMSA 
determined it could more quickly move a rulemaking that focused on the 
mandates from the 2011 Pipeline Safety Act by splitting out the other 
provisions contained in the NPRM into two other, separate rules. 
Accordingly, on October 1, 2019, PHMSA published a final rule titled 
``Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion 
of Assessment Requirements, and Other Related Amendments.'' \79\ PHMSA 
discusses the effects of that final rule on this proposal and any of 
the pertinent comments received on the ANPRM in the appropriate 
sections below.
---------------------------------------------------------------------------

    \79\ 84 FR 52180.
---------------------------------------------------------------------------

III. Analysis of ANPRM Comments and PHMSA's Response

    The deadline for submitting written comments on the ANPRM was 
October 1, 2018. PHMSA received comments from entities consisting of 
citizen groups; pipeline industry consulting groups; government 
agencies, including representatives from the State of New Jersey and an 
association of State pipeline regulators; pipeline operators; and 
pipeline industry trade associations. PHMSA also received comments from 
approximately 4,800 individuals. PHMSA has considered the feedback 
received to the ANPRM and has taken the information submitted into 
account in formulating this proposal.
    The comments submitted by the approximately 4,800 individuals were 
similar to one another and urged PHMSA to keep the class change rules 
as they are now until PHMSA completes gas safety rules to ensure that 
operators have TVC records of their systems, as recommended by NTSB. 
Further, these commenters noted that the existing special permit 
application process and NEPA requirements ensure that there is a review 
of the characteristics of pipe being proposed to be left in the ground 
and that the public has notice of those times when an operator is 
seeking to be exempted from strength or testing regulations, and that 
the current rules provide operators options other than pipe 
replacement, while assuring that pipe that stays in the ground is of 
known strength and that the public is made aware of proposed 
exemptions.
    The following subsections summarize the questions and proposals 
contained in the ANPRM, each of the relevant issues raised by the 
commenters, and PHMSA's responses to the comments. The comments, in 
their original form, and corresponding rulemaking materials can be 
viewed at www.regulations.gov under Docket ID: PHMSA-2017-0151.

A. Comments Related to the 2016 Proposed Gas Transmission Rule

    PHMSA received several comments on the class location ANPRM 
regarding the gas transmission NPRM that was issued in April 2016 and 
how provisions within that proposed rule would relate to potential 
changes to the class location regulations. There was broad agreement 
and support across all PHMSA's stakeholders, from public interest 
groups to the industry trade associations, for finalizing the 2016 Gas 
Transmission NPRM \80\ to implement important safety initiatives, 
provide regulatory certainty, and promote pipeline safety technology 
development. The PST, representatives from the State of New Jersey, and 
over 4,800 members of the public commented that any consideration of 
changes to the current class location regulations should be postponed 
until after the 2016 Gas Transmission NPRM went into effect to address 
critical safety issues that could influence this rulemaking.
---------------------------------------------------------------------------

    \80\ The Final Rule based on this NPRM was published on October 
1, 2019.
---------------------------------------------------------------------------

    In a combined submission, AGA, the American Public Gas Association 
(APGA), API, and INGAA (collectively, the ``Associations'') specified 
that any regulations regarding class locations should align with the 
2016 Gas Transmission NPRM. This statement was supported by many 
pipeline operators. Members of the pipeline industry and the 
Associations commented that the repair requirements detailed in the 
2016 Gas Transmission NPRM would be appropriate for managing the 
integrity of pipeline segments where the class location has changed.
1. PHMSA's Response to General Comments Related to the 2016 Proposed 
Gas Transmission Integrity Rule
    PHMSA is managing the potential changes to the class location 
regulations in this NPRM independently and based on their own merits. 
PHMSA acknowledges that many of the technical requirements previously 
proposed in the 2016 Gas Transmission NPRM are pertinent and applicable 
to the issues surrounding class location changes. In some cases, 
provisions that were proposed in the 2016 Gas Transmission NPRM were 
finalized in the 2019 Gas Transmission Final Rule. Comments that 
pertain to any of the provisions of the Class Location ANPRM 
referencing proposed changes in the 2016 Gas Transmission NPRM are 
addressed in the specific topic areas below.

B. Requiring Pipe Integrity Upgrades and Allowing Other Options for 
Class Location Changes

1. Summary of ANPRM Questions 1, 1a, and 2
    PHMSA requested comments on whether it should allow operators to 
upgrade the integrity of pipeline segments undergoing class location 
changes by using methods other than the existing methods of pressure 
reduction, pressure testing, pipe replacement, or special permits. For 
clarification, the ``pipe integrity upgrades'' referred to in the ANPRM 
are synonymous with the existing methods that operators must use (i.e., 
pressure reduction, pressure test, or pipe replacement) to confirm or 
revise MAOP in accordance with Sec.  192.611. PHMSA also asked whether 
it should require pipe integrity upgrades for areas where the class 
location has changed from a Class 1 to a Class 3 or from a Class 2 to a 
Class 4.
    Similarly, in question 2, PHMSA asked whether it should provide 
operators with the option of performing certain IM measures, in lieu of 
the existing measures, when class locations change from Class 1 to 
Class 3.
2. Summary of Comments
    The California Public Advocates Office commented that pipeline 
segments with adequate material properties records and a successful 
subpart J pressure test could be managed with the existing pipe 
integrity upgrades per Sec.  192.611. It said that, in areas where the 
class location has changed and the pipeline segment is missing material 
properties records and does not have documentation of a successful 
subpart J pressure test, either those pipeline segments should be 
replaced or the operator should be required to apply for a special 
permit. Finally, it said that if a pipeline segment undergoing a class 
location change is missing records but does have documentation of a 
previous successful subpart J pressure test, that segment could be 
managed with a new pressure test, pipe replacement, or a special 
permit.
    NAPSR and the PST remarked that the best way to ensure public 
safety is to continue to encourage pipe replacements and to allow PHMSA 
to issue special permits for class location changes. These commenters 
were skeptical that relying on operational

[[Page 65153]]

practices, including IM, would be sufficient to ensure public safety, 
given that many accidents have been linked to operators mismanaging IM. 
These commenters also noted that the combination of prescribed design 
factors and IM better ensures safety through redundancy, and that this 
redundancy is good for public safety.
    NAPSR and the PST also noted that, if IM concepts are used in lieu 
of pipe replacement, operators should be required to demonstrate 
improved safety levels through using IM program techniques or pressure 
test documentation.
    Comments received from TransCanada Corporation (now TC Energy), 
Kinder Morgan, the Associations, GPA Midstream Association (GPA 
Midstream), and a member of the public expressed the view that PHMSA 
should allow operators to have the option of managing changes in class 
location with integrity assessments. The Associations stated that PHMSA 
should encourage operators to adopt IM measures, including those in the 
existing IM regulations and the regulations proposed in the 2016 Gas 
Transmission NPRM, to address threats posed by class location changes. 
In doing so, the Associations suggested, operators would gain knowledge 
about their systems that they would not have otherwise obtained. In 
addition, Enbridge noted that landowner disturbance and customer impact 
would be greatly reduced by reducing the amount of pipe replacements or 
hydrostatic tests conducted when class locations change.
    Further, both Enbridge and the Associations suggested that PHMSA 
should allow operators to use integrity assessments as an MAOP 
confirmation (or revision) when class locations change, both from Class 
1 to Class 3 and from Class 2 to Class 4. These commenters noted that 
pipeline technology has advanced since PHMSA promulgated the class 
location regulations. Commenters from the industry further stated that 
these technological advancements are feasible methods of ensuring 
operational integrity while managing class location changes. Therefore, 
operators and the Associations requested that PHMSA consider updating 
the class location regulations by allowing operators to perform aspects 
of IM when class locations change. These commenters suggested that 
operators would be able to analyze the condition of their pipelines 
through site-specific assessments and make sound pipe replacement 
determinations rather than follow prescriptive requirements.
    Kinder Morgan added that regardless of the reason a class location 
changes, managing a class location change with IM principles is a more 
holistic approach than a ``one-time'' pipe replacement.
    GPA Midstream suggested that PHMSA ``should not impose arbitrary 
restrictions on an operator's ability to address class location changes 
with appropriate operations, maintenance, and integrity measures,'' as 
operators can conduct risk assessments to determine the potential 
threats to a pipeline segment where the class location has changed. GPA 
Midstream further suggested that PHMSA's focus should be on making sure 
that operators complete such risk assessments within a reasonable 
amount of time and that appropriate documentation is maintained to 
substantiate compliance.
    The Pennsylvania Grade Crude Oil Coalition (PGCOC), which 
represents small producers and refiners, stated that its members 
generally have limited resources compared with large pipeline 
operators. While the PGCOC supports an alternative to the current ways 
of managing class location changes, it requested that such an 
alternative not follow the framework of special permits. From its 
perspective, special permits contain numerous conditions that go beyond 
IM requirements and are unrelated to the change in class location. 
Furthermore, it suggested that the class-location regulations should 
provide certain exemptions or alternatives for small pipeline 
operators. Specifically, it suggested that PHMSA consider establishing 
minimal IM requirements for small operators.
    An individual citizen noted that when comparing the failures in San 
Bruno, CA, and Carlsbad, NM, neither was associated with the operating 
stress of the pipeline. Rather, both incidents were caused by defects 
in the pipe itself and that these incidents were preventable using IM 
tools and methods. Further, this individual suggested that arbitrary 
pipe replacement when class locations change is not necessary, and 
these decisions should be made based on well-understood pipe 
conditions.
3. PHMSA Response
    PHMSA agrees with many of the commenters that IM principles can 
serve as a useful and effective means of addressing the increased 
safety risks that accompany higher population densities near gas 
transmission pipelines. For this reason, in developing this proposed 
rule, PHMSA considered the ability of operators to demonstrate 
effectiveness and safety enhancements using IM performance metrics and 
methods. PHMSA also considered operators' recordkeeping practices and 
the documentation of previous pressure tests, as well as their ability 
to perform risk assessments. PHMSA's experience with class location 
change special permits demonstrates that IM methods can be appropriate 
for managing class location changes when implemented properly. 
Therefore, PHMSA is proposing to add an IM alternative to the existing 
class location change requirements for pipeline segments changing from 
a Class 1 to a Class 3 location.
    On the other hand, the existing IM program is not a panacea for 
managing such risks. Class locations provide safety throughout the 
Nation's pipeline network by specifying stronger minimum safety 
standards for MAOP and design, construction, testing, and O&M 
requirements in higher class locations. The IM regulations provide a 
separate structure by which operators can focus their resources on 
managing and improving pipeline integrity in areas where a failure 
would have the greatest impact on public safety. Over time, pipelines 
can degrade due to integrity threats such as corrosion and cracking. IM 
provides minimum safety margins for more densely populated areas by 
requiring operators to assess their pipelines at a minimum of every 7 
years, or more frequently, based on threat assessments or the predicted 
growth of anomalies found in HCAs.
    For these reasons, this NPRM would not change the existing 
requirements for class location changes for pipelines that do not meet 
the proposed eligibility conditions but would instead provide an 
additional alternative for compliance. Newly constructed pipelines 
would still be required to be constructed based on part 192 class 
location requirements. Based on PHMSA's experience with class location 
special permits, as well as inspection results and incident history, 
the agency does not believe that IM, as it exists in subpart O, is 
suitable as the only appropriate method for class location change 
management. The IM regulations were crafted for pipe that was designed 
to a higher safety factor, and were not crafted for Class 1 pipe. 
Because the IM alternative proposed in this rule would allow operators 
to leave Class 1 pipe in the ground in locations where the population 
has increased to a Class 3 level, PHMSA is not confident that IM 
requirements, alone, would be adequate for protecting the population in 
those locations.
    As a result, PHMSA is not proposing to allow pipe with higher-risk 
attributes

[[Page 65154]]

to be eligible for the proposed IM alternative, including: Bare pipe; 
pipe with wrinkle bends; pipe with certain weld seams (e.g., direct-
current (DC), low-frequency electric resistance welded (LF-ERW), 
electric flash-welded (EFW), lap-welded seams, or seams where the 
longitudinal joint factor is below 1.0); and pipe with SCC, selective 
seam weld corrosion, or girth weld cracking (pipe body or weld 
cracking) corrosion. In addition, PHMSA is imposing additional 
mitigation requirements beyond those currently required under IM. 
Operators with higher-risk attribute pipe could continue to apply for 
special permits to manage class location changes.
    PHMSA is also not proposing exceptions to the proposed IM 
alternative, as suggested by some commenters, because the existing 
options for class location change compliance and the special permit 
process would remain. Operators unable or unwilling to perform the IM 
alternative can achieve compliance through one of the existing options 
at Sec.  192.611 or via a special permit.
    PHMSA has not issued a special permit to manage locations changing 
from a Class 2 to a Class 4, because there is not an adequate basis for 
applying IM measures and concepts to these higher-risk pipeline 
segments. Though inspection technologies have advanced from earlier 
iterations, PHMSA does not have the operational data to confirm that 
the use of such technology on pipe designed to Class 2 standards would 
provide an adequate margin of safety in very densely populated Class 4 
locations with multi-story buildings. PHMSA is concerned that there 
would not be adequate, feasible measures that could be prescribed to 
provide Class 4 locations with an equivalent level of safety in lieu of 
replacing pipe.

C. Integrity Upgrades and Integrity Management Options for Clustered 
Areas

1. Summary of ANPRM Questions 1b, 3, 3a, and 3b
    In question 1b of the ANPRM, PHMSA asked whether part 192 should 
continue to require operators to upgrade pipeline integrity where the 
class location has changed from a Class 1 to a Class 3 due to the 
``cluster rule.'' \81\ In question 3, PHMSA asked whether the agency 
should give operators the option of performing certain IM measures in 
lieu of the existing measures when class locations change due to 
additional structures being built outside of an existing ``clustered'' 
areas within the sliding mile and operators are using the cluster 
adjustment to class locations per Sec.  192.5(c)(2).\82\ In sub-
questions 3a and 3b, PHMSA asked whether, if alternative IM measures 
are permitted for pipelines, then what additional IM and maintenance 
measures should be applied to offset the safety impact of additional 
structures being built outside of clustered areas and at what intervals 
and in what timeframes operators should be required to assess these 
pipelines and perform remediation measures.
---------------------------------------------------------------------------

    \81\ See Sec.  192.5(c)(2) and section I.B. of the ANPRM 
background for more details on the ``cluster rule.'' Operators can 
adjust the length of a Class 2, Class 3, or Class 4 location based 
on the presence of a ``cluster of buildings.'' Clustering reduces 
the amount of pipe that is subject to the safety requirements of 
higher class locations. Clustering does not change the length of the 
class location units themselves (i.e., the ``sliding mile'').
    \82\ Under Sec.  192.5(c)(2), the length of Class locations 2 
and 3 may be adjusted as follows: When a cluster of buildings 
intended for human occupancy requires a Class 2 or 3 location, the 
class location ends 220 yards (200 meters) from the nearest building 
in the cluster.
---------------------------------------------------------------------------

2. Summary of Comments
    Multiple commenters expressed the view that options for actions 
taken in response to class location changes should not depend on 
whether clustering was used in determining the class location 
designation.
    More specifically, the Associations strongly disagreed with PHMSA's 
statement in the ANPRM of a cluster being ``even a single house.'' They 
stated that in no prior class location rulemaking has the term 
``cluster'' ever been defined. The Associations noted that in 1992, 
PHMSA, in response to an ANPRM question, specified that the word 
``cluster'' was ``used in the ordinary dictionary sense,'' but, 
according to the Associations, the dictionary definition does not 
support the interpretation of one structure constituting a ``cluster.'' 
The Associations contended that the ordinary meaning of a cluster 
should continue to apply and each operator should be able to determine 
the scope of a cluster. Individual operator comments supported this 
view.
    TransCanada Corporation suggested that PHMSA revise the ``cluster 
rule'' in Sec.  192.5(c)(2) to cover only those situations where there 
are more than 10 buildings in close proximity, claiming that such a 
definition would be closer to the original intent of using class 
locations as a risk-mitigation tool and would be supported by a Class 1 
location being defined as one with fewer than 10 buildings. Further, 
TransCanada noted that this proposed definition is supported by PHMSA's 
recent issuance of a class location special permit that distinguished 
between two differently sized clusters (i.e., Type A and Type B), one 
with more and one with fewer than 10 buildings. Finally, it stated that 
categorizing low-population-density areas due to PHMSA's interpretation 
of the cluster rule as Class 3 locations artificially manipulates 
pipeline risk characterizations, in that small clusters of buildings 
(e.g., 3) near larger clusters of buildings (e.g., 50) would share the 
same risk profile. TransCanada stated that this approach results in 
outcomes that are inconsistent from the perspective of risk because a 
cluster with 50 buildings would have a higher activity rate, which 
would increase the likelihood of failure, and any failures would have 
higher consequences due to the denser population, whereas a cluster of 
3 buildings would have less.
    GPA Midstream also disagreed with assigning a single building as a 
defined cluster. It suggested that operators should determine the class 
location for the cluster specifically and determine the class location 
for the rest of the class location unit solely by considering the 
number of buildings outside of the clustered area. In this way, 
population density would drive class location determinations more 
accurately.
3. PHMSA Response
    The ``cluster rule'' only applies when an operator has identified a 
class location unit that meets the criteria for a Class 2, Class 3, or 
Class 4 location. Once the Class 2, Class 3, or Class 4 location has 
been identified, the operator may adjust the endpoints of that Class 2, 
Class 3, or Class 4 location by using the cluster rule.\83\ The purpose 
of this requirement is to allow operators to avoid replacing or 
pressure testing segments that have no buildings intended for human 
occupancy in the sliding mile and outside the ``cluster.''
---------------------------------------------------------------------------

    \83\ See Sec.  192.5(c).
---------------------------------------------------------------------------

    PHMSA is not proposing any revisions to the clustering methodology 
in this NPRM. However, this proposed rule would address areas that 
might be affected by clustering by requiring that operators assess pipe 
with ILI tools and implement P&M measures for the entire segment.

D. Using an Integrity Management Option To Manage Safety When Class 
Locations Change From a Class 1 to a Class 3

1. Summary of ANPRM Question 2a
    In question 2a of the ANPRM, PHMSA asked whether it should allow 
operators to use certain IM measures in

[[Page 65155]]

lieu of the existing measures to ensure safety when class locations 
change from a Class 1 to a Class 3, and if so, what additional IM and 
maintenance approaches or safety measures should be applied to offset 
any potential impact to safety. PHMSA also asked at what intervals 
operators should be required to assess such pipelines and perform the 
necessary remediation measures.
2. Summary of Comments
    NAPSR and the PST commented that specific design measures are more 
effective and consistently implemented than IM, as several recent 
failures have been attributed to IM implementation issues. Should PHMSA 
allow operators to use IM measures to manage class location changes, 
these commenters suggested that PHMSA should consider requiring more 
frequent integrity assessments, multiple tool type runs, more stringent 
repair requirements, and additional damage prevention activities.
    Members of the pipeline industry recommended that PHMSA allow 
operators to use IM principles for managing class location changes, 
noting such an approach would allow operators to determine the threats 
associated with each pipeline segment and appropriate actions. Industry 
commenters also suggested that operators could implement the integrity 
assessment option for class location change management similarly to how 
it is implemented in subpart O, with at least one commenter noting that 
they could classify class location change segments as HCAs and manage 
the segments as a part of a broader IM program. Therefore, these 
commenters suggested that for both covered and non-covered segments 
that experience a class location change, operators could complete an 
initial assessment within 24 months of the class change, with 
reassessments to occur within 7 years or 10 years, depending on where 
the segment is located and the status of the 2016 Gas Transmission 
NPRM. Operators could complete the initial assessments using, at a 
minimum, ILI or comparable technology capable of assessing corrosion 
and dents. To ensure all identified threats would be addressed, 
operators could use additional assessment methods.
    Certain industry commenters requested that PHMSA consider allowing 
operators to file for an extension if it is not practicable to complete 
an initial integrity assessment and MAOP reconfirmation, if required, 
within 24 months of a class change.
3. PHMSA Response
    PHMSA agrees with NAPSR and the PST that if IM is used to manage 
class location changes, additional and enhanced requirements would be 
necessary to ensure pipeline safety. PHMSA also agrees that the timing 
of the initial integrity assessment should correspond with the current 
class location change requirement of 24 months. PHMSA is proposing 
reassessment intervals for the IM alternative of class location change 
management equivalent to the reassessment intervals in subpart O. As 
proposed in this NPRM, any segments managed through this IM alternative 
would need to be classified as HCAs, which are subject to subpart O; 
therefore, such a requirement would be consistent with the current 
regulations. Operators that do not identify the Class 1 to Class 3 
location change in accordance with Sec. Sec.  192.609 and 192.611(d) 
would not be able to use the class location change alternative proposed 
in this NPRM.
    PHMSA agrees with commenters that IM is not suitable for class 
location change management in every situation. Under PHMSA's proposal, 
an operator would perform an analysis to identify those pipeline 
segments where the class location has changed, and identify those 
segments where it would be inappropriate to manage Class 1 to Class 3 
location changes with IM. PHMSA notes that even if a pipeline segment 
meets the proposed minimum criteria discussed later in this NPRM, it 
does not mean that IM would be the best option for managing that 
pipeline segment. Based on their knowledge of their own pipeline 
systems, operators would ultimately determine whether an eligible 
pipeline segment should be managed with the IM alternative.
    As a condition of using the IM alternative proposed in this rule, 
operators must notify PHMSA of their intent to use the alternative to 
allow PHMSA to review and inspect for compliance. PHMSA has learned 
through its inspections that many operators fail to assess and mitigate 
integrity problems properly, including poor construction practices \84\ 
and operational maintenance threats, whether due to a lack of 
appropriate technologies, cost, or other reasons, threats that 
ultimately lead to pipeline failures. IM programs can fail to account 
for broadly recognized safety issues, such as bare pipe, wrinkle bends, 
lap welds, cracking, and pipe that has other potential construction or 
manufacturing issues. ILI technology does not effectively identify all 
integrity threats that may have been created through construction or 
manufacturing processes and that have not been tested for stability 
with a subpart J pressure test. Therefore, PHMSA believes such segments 
should not be managed using the IM alternative when class locations 
change.
---------------------------------------------------------------------------

    \84\ On several occasions in recent years, PHMSA has met with 
operators to discuss safety issues related to new construction. For 
example, PHMSA hosted a public workshop in collaboration with its 
State partners, the Federal Energy Regulatory Commission (FERC), and 
Canada's National Energy Board in April 2009. The objective of the 
public workshop was to inform the public, alert the industry, review 
lessons learned from inspections, and improve new pipeline 
construction practices prior to the 2009 construction season. The 
following website contains information discussed at the workshop and 
provides a forum in which to share additional information about 
pipeline construction concerns: https://primis.phmsa.dot.gov/construction/index.htm.
---------------------------------------------------------------------------

    Further, as the 2010 PG&E incident at San Bruno, CA, revealed, some 
operators may not have TVC records of certain pipe properties, such as 
pipe material yield strength, pipe wall thickness, pipe seam type, pipe 
and seam toughness, and coating type or quality. Data on these pipe 
properties are critical and necessary for the effective implementation 
of IM processes and pipeline safety measures in populated areas. PHMSA 
is concerned that operators may not have this pipe material property 
data for Class 1 pipe segments in locations that later become Class 3, 
especially if the pipe has been operated in accordance with Sec.  
192.619(c).\85\ This data is necessary for making important pipeline 
safety judgments, including technical evaluations of anomalies.
---------------------------------------------------------------------------

    \85\ Pipeline segments operated in accordance with Sec.  
192.619(c) were installed prior to adoption of the PSR and likely do 
not meet Sec.  192.619(a)(1), (2), or (4), or they operate above 72 
percent of SMYS. These pipeline segments may not have pressure test 
or material properties records. Section 192.619(c) allows pipelines 
put into service before July 1, 1970, that were found to be in 
satisfactory condition, to be operated in Class 1 locations at the 
highest actual operating pressure they achieved during the 5 years 
preceding July 1, 1970, regardless of the level of hoop stress on 
the pipe. Pipelines in Class 1 locations that are designed and 
operated to part 192 standards are otherwise limited to a maximum 
operating hoop stress of 72 percent of SMYS.
---------------------------------------------------------------------------

    PHMSA also notes that there may be instances where a pipeline 
appears to be in ``good condition'' from a visual standpoint, but may 
not have the initial pipe manufacturing, pipe body and seam strength, 
construction quality, coating, and CP effectiveness to prevent 
corrosion and cracking, and therefore lack the O&M history necessary 
for the effective management of class location changes using IM.

[[Page 65156]]

    Therefore, PHMSA proposes to exclude pipe with certain pipe 
attributes and O&M parameters from the proposed IM alternative of 
managing class locations. PHMSA is concerned that some operators have 
not adequately identified and mitigated these integrity threats at a 
consistent and reliable level. Excluding these segments from the 
proposed IM alternative would ensure a higher level of safety. 
Operators would still be allowed to apply for special permits to manage 
such pipeline segments, but PHMSA would be able to evaluate them, and 
the public would be able to comment on them, on a case-by-case basis. 
PHMSA requests comment as to whether these proposed pipe eligibility 
conditions could be modified or eliminated, and if so, what the impacts 
to safety and the environment would be as well as the net benefits of 
this proposed rule.
    In addition, PHMSA's experience with operator IM programs indicates 
that some operators do not have an IMP in place that includes 
sufficiently robust P&M measures in HCAs to address the various risks 
posed by changes in class locations. Therefore, PHMSA concludes that, 
while applying modern IM assessments and processes can be an 
appropriate way to manage certain class location changes, the addition 
of specific prescriptive, additional P&M measures to such a method is 
needed to ensure a level of safety comparable to pipe replacement or 
derating the pipeline MAOP for pipeline segments that change from a 
Class 1 to Class 3 location. PHMSA requests comment as to whether 
modification or elimination of any of the proposed P&M measures, beyond 
the current IM requirements, is feasible and what the impacts to safety 
and the environment would be and whether such a change would maximize 
nets benefits to society.
    Regarding the request that PHMSA allow operators to file for an 
extension to the 24-month assessment timeframe, PHMSA is not proposing 
to adopt that suggestion. PHMSA believes that 24 months is sufficient 
time to complete an initial IM assessment and that longer time frames 
would introduce undue risk to public safety by allowing Class 1 pipe to 
operate untested for more than 2 years in a Class 3 location. 
Currently, under Sec.  192.611, if a class location change requires 
pipe replacement, MAOP reduction, or pressure tests to confirm a class 
location upgrade to be conducted, operators must complete those actions 
within 24 months of the class location change. PHMSA notes that the 
timeframe for this requirement was established at 24 months because it 
provides operators with enough time to order pipe, if necessary, and 
make changes from one season to the next. For example, if a class 
location change occurs in the spring, an operator would be able to 
order and receive pipe before replacing the pipe in the following 
summer season.

E. General Eligibility for Managing Class Location Changes With 
Integrity Management

1. Summary of ANPRM Questions 4, 4a, 4b, and 4c
    In question 4 of the ANPRM, PHMSA requested comment on whether an 
operator should use a ``fitness-for-service'' \86\ standard to 
determine which pipelines should be eligible for using IM measures to 
manage segments changing from a Class 1 to a Class 3 location, and what 
factors should make a pipeline eligible or ineligible for doing so.
---------------------------------------------------------------------------

    \86\ ``Fitness for service'' refers to a pipeline's ability to 
operate and deliver product safely while protecting the people and 
environment around the pipeline. Fitness for service has been a part 
of industry consensus standards since the mid-1980s, and PHMSA has 
incorporated elements of these standards into the PSR.
---------------------------------------------------------------------------

    PHMSA also asked whether it should base a proposed class location 
change management IM on the alternative criteria it uses when 
considering class location change waivers, including the pipe's age, 
the manufacturing and construction processes of the pipe, and the 
pipe's O&M history.
    In addition, PHMSA asked whether it should require operators and 
pipelines to meet eligibility conditions outlined in the 2004 Federal 
Register Notice, including no bare pipe or pipe with wrinkle bends, 
records of a hydrostatic test to at least 1.25 times MAOP, records of 
ILI runs with no significant anomalies that would indicate systemic 
problems, and an agreement that up to 25 miles of pipe both upstream 
and downstream of the waiver location must be periodically inspected 
using ILI technology.
2. Summary of Comments
    NAPSR and the PST stated that the existing Sec.  192.609 serves as 
a fitness-for-service determination and suggested that operators should 
complete a fitness-for-service study for all pipeline segments, not 
just those impacted by a class location change. NAPSR and the PST 
further suggested that such a study should then be updated every 3 
years, noting that the study results could assist in pipe replacement 
determinations when a class location change occurs. Pipeline industry 
commenters stated that a fitness-for-service standard should be 
established from the integrity assessments, enhanced repair criteria, 
and MAOP reconfirmation requirements proposed in the 2016 Gas 
Transmission NPRM. They stated that the initial MAOP establishment (or 
an MAOP reconfirmation where a pressure test record is not available) 
sets a physical safety margin that is then maintained for the life of 
the pipeline using integrity assessment, anomaly evaluation, and repair 
or replacement, where required based on pipe condition.
    NAPSR, the PST, and the California Public Advocates Office 
commented that the criteria for class location change special permits 
that PHMSA published in the 2004 Federal Register Notice are all 
aspects of fitness-for-service, and PHMSA should use these factors as a 
basis for any proposed class location change requirements. Similarly, 
NAPSR and the PST commented that PHMSA should approve, on a case-by-
case basis, an operator's request to utilize IM measures for class 
location changes taking into account a fitness-for-service study. The 
PST also said that PHMSA should not issue class location change special 
permits if the applicable pipeline segment cannot be assessed with ILI 
tools or does not have accurate and verifiable design records.
    The Associations and supporting operators broadly commented that 
threshold conditions should not be required and that PHMSA should allow 
operators to use IM measures in lieu of pipeline replacement on all 
segments undergoing class location changes, stating that no individual 
pipe attribute should determine eligibility for a class location change 
alternative. Instead, these commenters suggested that PHMSA should 
encourage operators to utilize IM measures exclusively in lieu of the 
current requirements for managing these segments of pipelines where the 
class location has changed, including addressing threats as detailed in 
existing regulations and as proposed in the 2016 Gas Transmission NPRM. 
In doing so, these commenters argued, operators would gain knowledge 
about their systems that they would not have obtained otherwise.
    Some operators, including TransCanada Corporation, proposed that 
operators should be allowed to conduct site-specific assessments to 
determine if pipeline segments should be eligible for using IM measures 
in lieu of pipe replacements or pressure reductions. Such an assessment 
would need to assess all applicable threats and their interactions to 
ensure that operators can manage safety at acceptable levels. An 
individual citizen noted that the acceptable current fitness-for-
service standards are in ASME B31.8S, ASME B31G, RSTRENG, and their 
equivalents. This citizen further stated that

[[Page 65157]]

reassessment is the key to assuring continued safety, and that lower 
stress does not assure public safety. The commenter further suggested 
that pipe segments should not be changed out if its condition is well 
understood and judged to be acceptable.
    In addition, the Associations and supporting pipeline operators 
claimed that PHMSA's special permit requirement for assessing a 
prescribed amount of mileage upstream and downstream from the pipeline 
segment undergoing a class location change is not technically 
justified. They said that depending on the design of a pipeline system, 
such an assessment may require multiple tool runs or the analysis of 
pipe completely unrelated to the segment in which the class location 
has changed. Because PHMSA proposed to extend integrity assessments 
outside of HCAs in the 2016 Gas Transmission NPRM, these commenters 
suggested that special permit inspection areas are no longer 
appropriate or necessary to ensure pipeline safety. Similarly, Kinder 
Morgan stated that IM measures address segment threats, and the 
additional requirements detailed in the 2016 Gas Transmission NPRM will 
cover pipeline segments up and downstream of the class-location change.
    An individual citizen commented that prescribing mileage to be 
assessed is not appropriate, as it could potentially exempt from the 
requirements pipeline segments that do not have 50 miles of pipe 
between ILI tool launcher and receivers.
    Another individual citizen recommended that, if PHMSA were to allow 
an IM alternative for class location changes, operators should have to 
inform PHMSA and affiliated State agencies of their intent to apply IM 
measures for managing a pipeline segment changing from a Class 1 to a 
Class 3 location.
3. PHMSA Response
    To the PST's comment that class location change special permits 
should not be issued if the applicable pipeline segment cannot be 
assessed with ILI tools or does not have accurate and verifiable design 
records, PHMSA is proposing to require in this NPRM that the segment 
must be ``piggable'' to be eligible for the IM alternative to the class 
location change requirements. Operators must also have pipe material 
property records for the segment to be eligible.
    PHMSA does not believe that assessments and repairs alone are 
adequate to demonstrate the eligibility and fitness-for-service of pipe 
manufactured to Class 1 location standards to be used in Class 3 
locations. In addition, PHMSA has elected to finalize the provisions 
proposed in the 2016 Gas Transmission NPRM in three separate final 
rules--the 2019 Gas Transmission Final Rule was published October 1, 
2019, and the other two are in development. While the 2019 Gas 
Transmission Final Rule did include updated assessment requirements for 
``moderate consequence areas,'' PHMSA intends to finalize the 
corresponding repair criteria in a draft final rule currently titled 
``Pipeline Safety: Safety of Gas Transmission Pipelines, Repair 
Criteria, Integrity Management Improvements, Cathodic Protection, 
Management of Change, and Other Related Amendments.'' PHMSA does not 
believe that managing Class 1 to Class 3 location changes using an 
updated assessment schedule with the existing repair criteria would 
provide an equivalent level of safety when compared to pipe replacement 
without additional P&M requirements being applied to the eligible pipe. 
ASME B31.8S allows anomalies to grow until only a 10 percent safety 
factor remains before they need to be remediated. In this NPRM, PHMSA 
is proposing that operators remediate anomalies that have a predicted 
failure pressure of less than 1.39 or a depth of less than 40 percent 
of the pipe wall thickness. This safety factor of 1.39 would be similar 
to the installation of new Class 1 pipe.
    Further, PHMSA agrees with NAPSR and the PST that the study 
performed under the requirements at Sec.  192.609, when a pipeline's 
class location changes is, in many ways, a type of fitness-for-service 
study. PHMSA is hesitant to incorporate a general requirement for 
operators to perform a fitness-for-service evaluation because PHMSA is 
concerned that such an evaluation would not result in a consistently 
applied minimum safety standard across the industry. Therefore, the 
specific eligibility conditions PHMSA is proposing in the IM 
alternative for threat identification in this NPRM would be akin to 
prescribing a fitness-for-service standard that operators would have to 
meet to use the IM alternative.
    For the purposes of an operator determining if a segment would be 
``fit for service'' to apply IM measures for managing pipeline segments 
changing from a Class 1 to a Class 3 location, PHMSA is proposing a set 
of pipe attributes that would disqualify a segment from using the IM 
alternative based on threats and their higher risks. Those attributes, 
and the corresponding threats, are:
    (1) Bare pipe, which cannot maintain proper CP currents;
    (2) Pipe with wrinkle bends, which can be prone to cracking;
    (3) Pipe without records reflecting key attributes, including 
diameter, wall thickness, grade, seam type, yield strength, and tensile 
strength, which do not allow for proper anomaly evaluation;
    (4) Pipe uprated in accordance with subpart K but without a 
pressure test to at least 1.39 times MAOP, unless the segment passes a 
subpart J pressure test for a minimum of 8 hours at a minimum pressure 
of 1.39 times MAOP within 24 months after the Class 1 to Class 3 
location segment change and prior to uprating the MAOP. PHMSA believes 
that allowing pipe that has been operated for years at a lower pressure 
to be uprated without additional requirements presents undue risk;
    (5) Pipe that has not been pressure tested in accordance with 
subpart J for 8 hours at a minimum test pressure of 1.25 times MAOP, 
unless the segment passes a subpart J pressure test for a minimum of 8 
hours at a minimum pressure of 1.25 times MAOP within 24 months after 
the Class 1 to Class 3 segment change. The treatment of this attribute 
is consistent with the current regulatory requirements and will not 
allow pipeline segments that have been operating in accordance with 
Sec.  192.619(c), which may lack material records or be operated above 
72 percent SMYS, to be managed under the IM alternative;
    (6) Pipe with DC, LF-ERW, EFW, or lap-welded seams, or with a 
longitudinal joint factor below 1.0, which are prone to seam failure 
due to cracking and improper jointing that results in lower-strength 
joints;
    (7) Pipe, in or within 5 miles of the Class 1 to Class 3 location 
segment, with cracking in the pipe body, seam, or girth welds that is 
over 20 percent of the pipe wall thickness; \87\ has a predicted 
failure pressure less than 100 percent of SMYS; has a predicted failure 
pressure less than 1.5 times MAOP; \88\ has experienced a leak or 
rupture due to pipe cracking; or for which an analysis indicates the 
pipe could fail in brittle mode. Cracking leads to ruptures on pipe 
segments with poor toughness properties;
---------------------------------------------------------------------------

    \87\ In PHMSA's experience, current ILI tool detection 
effectiveness for cracks is at approximately 10 to 20 percent depth.
    \88\ This threshold is based on a related recommendation from 
the Gas Pipeline Advisory Committee on repair criteria. See https://primis.phmsa.dot.gov/meetings/MtgHome.mtg?mtg=132 for more details.

---------------------------------------------------------------------------

[[Page 65158]]

    (8) Pipe with poor external coating that requires negative cathodic 
polarization voltage shifts of 100 millivolts or more,\89\ or linear 
anodes to maintain cathodic protection, or pipe with tape wraps or 
shrink sleeves. The treatment of this attribute is consistent with 
Appendix D to part 192, which is referenced at Sec.  192.463. Such pipe 
may have issues with corrosion control or cracking;
---------------------------------------------------------------------------

    \89\ A.W. Peabody, ``Peabody's Control of Pipeline Corrosion,'' 
second edition, ``Criteria for Cathodic Protection.'' ``The 100 mV 
polarization criterion should not be used in areas subject to stray 
current because 100 mV of polarization may not be sufficient to 
mitigate corrosion in these areas. It is generally not possible to 
interrupt the source of the stray currents to accurately measure the 
depolarization. To apply this criterion, all DC current sources 
affecting the structure, including rectifiers, sacrificial anodes, 
and bonds must be interrupted. In many instances, this is not 
possible, especially on the older structures for which the criterion 
is most likely to be used. The 100 mV polarization criterion should 
not be used on structures that contain dissimilar metal couples 
because 100 mV of polarization may not be adequate to protect the 
active metal in the couple. This criterion also should not be used 
in areas where the intergranular form of external SCC, also referred 
to as high-pH or classical SCC is suspected. The potential range for 
cracking lies between the native potential and -850 mV (CSE) such 
that application of the 100 mV polarization criterion may place the 
potential of the structure in the range for cracking.''
---------------------------------------------------------------------------

    (9) Pipe transporting gas that is not of a suitable composition 
quality for sale to gas distribution customers, such as sour gas, which 
can lead to issues with corrosion; and
    (10) Pipe that operates in accordance with Sec.  192.619 (c) or 
(d).
    Operators with such higher-risk pipeline segments would still be 
able to apply for a special permit for class location change 
management. Operators with pipeline segments that do not have any of 
the listed disqualifying attributes could use the IM alternative. PHMSA 
believes this proposed approach is a way to establish if Class 1 pipe 
is suitable (``fit for service'') for operators to use IM methods to 
verify MAOP in a Class 3 location, while providing an equivalent level 
of safety, over the life of a pipeline, as pipe replacement. As the 
majority of these disqualifying attributes have been used to ensure 
safety in class location special permits for several years, 
incorporating these disqualifying attributes into this rulemaking 
should provide an equivalent level of safety compared to the special 
permits. PHMSA requests comment as to whether these eligibility 
conditions are appropriate, and whether the elimination or modification 
of them would impact safety, and how. Is there an alternative approach 
PHMSA could take that would modify or eliminate these eligibility 
conditions that would maintain safety and increase the net benefits of 
this rulemaking?
    PHMSA agrees with commenters that requiring operators to assess an 
additional 25 miles upstream and downstream from the class location 
change is unnecessary. When the general special permit conditions were 
drafted in 2004, PHMSA used the 25-mile inspection area as a sort of 
proxy for the length of pipeline between an ILI tool launcher and 
receiver. PHMSA is proposing to require instead that operators assess 
the length of pipeline between the ILI tool launcher and receiver 
containing the Class 1 to Class 3 location segment without prescribing 
a specific numeric value for the mileage to be assessed. The ILI tool 
launchers and receivers are the natural beginning and endpoints for an 
inspection area rather than an arbitrary amount of mileage.
    PHMSA believes that approving each case in which an operator uses 
the proposed IM alternative for managing class location changes in lieu 
of pipe replacement is unnecessary for public safety and would not be 
significantly more efficient than the current approach of operators 
applying for special permits. However, PHMSA is proposing a 
notification requirement so that PHMSA and applicable State agencies 
are aware of each instance in which an operator uses the proposed IM 
alternative. This notification requirement will allow PHMSA and State 
regulators to know where these pipeline segments are located and can 
consider them when conducting inspections.

F. Eligibility for Pipe Operating in Accordance With Sec.  192.619(c)

1. Summary of ANPRM Questions 1c and 4a(i)
    In the ANPRM, PHMSA requested comments on whether pipe operating in 
accordance with Sec.  192.619(c) (e.g., pipeline segments with 
operating pressures above 72 percent SMYS, pipeline segments without a 
pressure test or with an inadequate pressure test, or pipeline segments 
with inadequate or missing material properties records), should be 
eligible for class location change management using IM principles. 
PHMSA also asked if part 192 should continue to require pipe integrity 
upgrades for pipeline segments operating in accordance with Sec.  
192.619(c).
2. Summary of Comments
    NAPSR and the PST commented that pipeline segments operating in 
accordance with Sec.  192.619(c) that lack design, material, or 
pressure test records should be required to follow the existing class 
location change requirements. They also seemed to suggest that, if 
PHMSA moved towards providing an IM alternative to class location 
changes, operators could incorporate pipeline segments operating in 
accordance with Sec.  192.619(c) that have undergone a class location 
change into their IM programs if they performed more robust integrity 
assessments and mitigation measures on those segments.
    The California Public Advocates Office requested that PHMSA confirm 
pipeline segments operating in accordance with Sec.  192.619(c) will 
not be allowed to continue operating in accordance with Sec.  
192.619(c) after a class change, consistent with current regulations 
and interpretations. Specifically, they noted that PHMSA interpretation 
PI-14-0005 states:

    If an operator uses Sec.  192.619(c) to establish the MAOP, the 
operator must have documentation of the pipeline segment's condition 
and operating and maintenance history, including historical pressure 
records for the maximum operating pressure to which the entire 
pipeline segment was subjected during the 5 years prior to July 1, 
1970. Section 192.619(c) cannot be used to determine the MAOP after 
a change in Class Location. Section 192.611 can be used to revise 
the MAOP within 24 months after a Class Location change; after that 
deadline, the MAOP must be revised according to Sec.  192.619(a).

    The Associations and supporting operators recommended an IM 
alternative that would include hoop stress limitations as follows: 80 
percent of the SMYS in Class 2 locations; 72 percent of SMYS in Class 3 
locations; and 60 percent of SMYS in Class 4 locations. These 
commenters noted that a hoop stress limitation of 80 percent for Class 
2 locations is supported by several existing special permits.
    The Associations and supporting operators also noted that the 2016 
Gas Transmission NPRM provides a means for reconfirmation of MAOP for 
pipeline segments operating in accordance with Sec.  192.619(c).\90\ So 
long as operators complete MAOP reconfirmation within 24 months of the 
class change, these commenters believed pipeline segments operating in 
accordance with Sec.  192.619(c) should be eligible for the class 
location change alternative. However, these commenters also stated that 
the MAOP reconfirmation test factor used should correspond with the 
class location and installation date at the time of construction, 
claiming that if PHMSA enforced the use of current

[[Page 65159]]

class location test factors, it would likely result in pipe 
replacements or pressure reductions that undermine the application of 
IM principles due to the class location change segment not being 
designed to meet the Class 3 pressure test factors.
---------------------------------------------------------------------------

    \90\ See 84 FR 52196 and 84 FR 52247.
---------------------------------------------------------------------------

    An individual citizen commented that the hoop stress of a pipeline 
segment cannot be determined if it has an unknown outside diameter, 
wall thickness, and SMYS. This commenter asked how an operator would be 
able to comply with class location change requirements if these values 
were unknown. If these variables were known, this commenter stated, 
then a multi-tool ILI inspection program in conjunction with chemical 
and physical sample tests would provide comparable assurance of 
compliance and safety.
3. PHMSA Response
    Commenters are divided on whether pipeline segments operating in 
accordance with Sec.  192.619(c) should be eligible for being managed 
with an IM alternative when class locations change. Pipeline segments 
operating in accordance with Sec.  192.619(c) were installed prior to 
adoption of the PSR and that do not meet Sec.  192.619(a)(1), (2), or 
(4), or they operate above 72 percent of SMYS. These pipeline segments 
may not have pressure test or material properties records.\91\ Section 
192.619(c) requires that an operator must still comply with Sec.  
192.611 should a class location change occur. This, in effect, 
precludes pipeline segments that operate in accordance with Sec.  
192.619(c) from continuing to operate without a pressure test or 
pressure reduction and records of pipe material properties when the 
class location changes. Given that pipeline segments operating in 
accordance with Sec.  192.619(c) tend to be higher risk,\92\ PHMSA's 
proposal states that pipeline segments operating at greater than 72 
percent SMYS and pipeline segments that are missing pipe material 
properties records are not candidates for the proposed IM alternative 
to class location change management.
---------------------------------------------------------------------------

    \91\ This data is included in PHMSA's annual reports. Pipeline 
operators are required to report which pipelines operate at greater 
than 72% SMYS, which method of MAOP determination was used for the 
pipeline, and whether the pipeline has incomplete records.
    \92\ Operators may know the material properties of pipeline 
segments operating in accordance with Sec.  192.619(c). However, 
many pipeline segments operating in accordance with Sec.  192.619(c) 
lack adequate material records, and may be operating at higher 
stress levels (above 72 percent SMYS) than what the pipe design 
would allow, if the pipe were to be constructed to today's 
standards.
---------------------------------------------------------------------------

    However, in this NPRM, PHMSA proposes that operators of pipelines 
that were previously operating in accordance with Sec.  192.619(c) that 
operate at or below 72 percent SMYS be eligible for the IM alternative 
only if the operator pressure tests any of those pipelines that do not 
have a record of a previous pressure test within 24 months after the 
class location change and have pipe material records for the segment. 
PHMSA proposes such a pressure test must meet current subpart J 
requirements for a new segment installed in a Class 2 location (the 
test pressure must be at least 1.25 times MAOP for 8 continuous hours). 
Operators would need to test such pipeline segments to Class 2 
standards rather than Class 3 standards because testing Class 1 pipe to 
Class 3 standards would result in a rupture and would require the 
operator to replace the pipe. This approach is consistent with the 
special permit conditions PHMSA has imposed on pipelines previously 
operating in accordance with Sec.  192.619(c).
    PHMSA is also proposing that this pressure-testing approach would 
apply to pipeline segments uprated in accordance with subpart K, except 
the pressure test for uprating the MAOP on a pipeline segment where the 
operator lowered the MAOP for a Class 1 to Class 3 location change 
would require a subpart J pressure test of 1.39 times the uprated MAOP 
for 8 continuous hours. Under this approach, operators would still be 
allowed to apply for a special permit for pipeline segments with the 
MAOP established in accordance with Sec.  192.619(c) that would not 
meet the proposed requirements. Typically, an operator will downrate 
the pressure of a pipeline segment because the segment is not meeting 
regulatory standards and the contractual flow volumes have diminished 
(i.e., they have lost customers). PHMSA is adding this requirement 
because if a pipeline is being uprated, it means that it has been 
operating at a lower pressure than to what the operator wants to raise 
the MAOP. Therefore, an operator must conduct a pressure test to a 
level that will justify the new, higher MAOP.
    To the Associations' point regarding hoop stress limitations, class 
location change special permits have been limited to Class 1 to Class 3 
location changes only. With the publication of the alternate MAOP rule 
in 2008,\93\ PHMSA allowed pipelines to operate up to 80 percent SMYS 
in Class 1 locations if those pipelines were built to certain 
specifications and are operated with procedures that are additional 
(e.g., 49 CFR 192.112, 192.328, and 192.620) to the normal procedures 
for pipelines operated at 72 percent SMYS. Pipelines built for Class 1 
and Class 2 locations were not designed or constructed to operate at a 
hoop stress up to 80 percent SMYS. Should operators conclude that their 
design, construction, and operation procedures fulfill the standards of 
the Alternate MAOP rule at Sec. Sec.  192.112, 192.328, and 192.620, 
then they can apply for a special permit in accordance with Sec.  
190.341.
---------------------------------------------------------------------------

    \93\ ``Standards for Increasing the Maximum Allowable Operating 
Pressure for Gas Transmission Pipelines,'' 73 FR 62148 (Oct. 17, 
2008).
---------------------------------------------------------------------------

G. Eligibility for Pipe With Specific Conditions and Attributes

1. Summary of ANPRM Questions 4a(ii), 4a(iii), 4a(vii), and 4a(viii)
    In question 4 of the ANPRM, PHMSA requested comments on whether 
specific pipe conditions should affect a pipeline segment's eligibility 
for an IM alternative for class location management.
    Specifically, PHMSA requested comments on whether pipeline segments 
that have a failure or leak history, were manufactured with a material 
or seam welding process during a time or by a manufacturer that has 
been shown over time to experience known integrity issues, or have 
lower toughness in the pipe and weld seam (e.g., Charpy impact value 
\94\), should be eligible for an IM alternative. PHMSA also asked 
whether pipeline segments that contain or are susceptible to cracking, 
including in the body, seam, or girth weld, or pipeline segments that 
have disbonded coating or CP shielding coatings, should be eligible for 
the IM alternative. Further, PHMSA asked whether pipe with seams that 
are lap-welded, flash-welded, low-frequency electric resistance welded; 
are of ``unknown'' type; have a history of seam failure due to poor 
manufacturing properties; or have a derating factor below 1.0, should 
be eligible for an IM alternative.
---------------------------------------------------------------------------

    \94\ 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.
---------------------------------------------------------------------------

2. Summary of Comments
    The California Public Advocates Office stated that pipeline 
segments should not be eligible for the IM alternative for class 
location change management if they have experienced an in-service 
failure, have manufacturing issues, or have a lower toughness in the 
weld seam. It proposed that PHMSA consider holding a

[[Page 65160]]

workshop to determine appropriate leak history thresholds and prescribe 
the eligibility of pipe with known integrity issues. It also commented 
that, if the operator does not know the seam type, the operator must 
determine the seam type or be required to use a longitudinal joint 
factor of 0.8 in any design calculations, even if the operator asserts 
all possible seam types merit a value of 1.0. It also expressed that, 
regardless of whether IM measures are deemed appropriate, the derating 
factor should be the more conservative of either the derating factor 
used at the time of construction or current design factors.
    TransCanada Corporation commented that operators should conduct a 
site-specific assessment taking into consideration pipe design, 
history, and environmental factors to determine whether particular 
pipeline segments should be eligible for an IM alternative when class 
locations change. It argued that pipeline segments should be eligible 
if operators can use integrity measures to manage any associated 
threats effectively. It noted that lap-welded pipe was an exception and 
should not be eligible for IM measures, as current inspection 
technology is not sufficient in determining lap-weld seam integrity.
    NAPSR and the PST expressed the view that PHMSA should consider all 
the factors listed in Question 4 of the ANPRM, including whether a 
pipeline is operating in accordance with Sec.  192.619(c), has 
experienced an in-service failure, or has significant corrosion or 
other damage; the age of the pipe; manufacturing and construction 
history; O&M history; and the criteria listed in the 2004 Federal 
Register Notice for determining which pipeline segments would be 
eligible for operators to apply IM measures when managing class 
location changes in lieu of replacing pipe.
    An individual citizen commented that pipe that has experienced an 
in-service failure should not be excluded so long as all comparable 
remaining defects in the segment have been remediated. This commenter 
suggested that pipeline segments with manufacturing defects should not 
be excluded from using an IM alternative when class locations change, 
so long as the operator has conducted a successful pressure test at 
1.25 times the MAOP. Such a pressure test would demonstrate that the 
manufacturing defect should be considered stable and will not grow 
while the pipeline is in service. This commenter stated that while the 
Charpy impact value is shown to be related to crack growth, it is not a 
factor in corrosion and pressure stress cycles in gas pipelines are not 
a concern. This citizen also noted that, for unknown seam type, an ILI 
tool should be able to identify seam type given each seam type's 
distinct magnetic signature.
3. PHMSA Response
    Based on the input provided and PHMSA's experience with special 
permits and incident investigations, PHMSA is persuaded that some of 
the attributes discussed, such as past incident history and toughness 
properties, can be effectively managed through an operator's IM program 
with mandatory P&M measures. In an operator's IM program, an operator 
addresses pipeline segments with an incident history through assessing 
and repairing or remediating the threats and causes associated with 
those past incidents. In this NPRM, PHMSA is proposing that operators 
would identify in their IM programs the specific Class 1 to Class 3 
location segments being managed under that program. In doing so, 
operators would be required to conduct a data integration and risk 
assessment on these segments, including an evaluation of past incident 
history, for all threats and establish an integrity assessment program 
to find and remediate applicable threats.
    This proposed rule specifies requirements for operators to maintain 
a comparable level of safety for the life of the pipeline segment that 
changed from a Class 1 to a Class 3 location. In response to the 
California Public Advocates Office's comment regarding derating 
factors, PHMSA believes that these requirements, including the IM 
principles and eligibility criteria prescribed in this NPRM, will 
provide the equivalent of conservative derating factors. PHMSA has 
issued several special permits over the past 15 years containing 
conditions identical to or similar to the conditions being proposed in 
this rulemaking for managing class location change waivers. Those 
special permits that PHMSA has issued have not resulted in any decrease 
in pipeline safety in the areas where they are implemented and in fact 
have resulted in no incidents on the applicable pipe. PHMSA, therefore, 
has confidence that the IM principles and eligibility criteria being 
proposed in this rulemaking will provide an equivalent level of safety 
consistent with the regulations.
    PHMSA believes that pipeline segments with known cracking issues 
are problematic and is proposing that operators would not be allowed to 
use the IM alternative for class location change management for those 
pipeline segments with cracks that exceed 20 percent of wall thickness. 
PHMSA reached this threshold by considering the current state of ILI 
technology and its tolerance for finding crack indications; current ILI 
tools can consistently evaluate crack depth and length at this level. A 
20 percent through-wall defect of the pipe, whether from cracking or 
corrosion, has a minimal effect on a pipeline's failure pressure ratio 
based on any of the approved defect analysis methods, such as R-STRENG 
or API 579. Operators of pipelines with cracking issues would continue 
to be eligible for class location change special permits.
    Material toughness is important when evaluating cracks and crack-
like defects, as cracking can weaken a pipe to the point where it might 
rupture.\95\ Since PHMSA is proposing to exclude pipe with known, non-
trivial cracking issues, PHMSA does not propose to include material 
toughness as an eligibility criterion for managing class location 
changes through IM. However, operators of pipeline segments that change 
from a Class 1 to a Class 3 location that identify cracking issues 
after implementing the proposed IM alternative for class location 
changes must evaluate the significance of those crack anomalies. PHMSA 
proposes to require crack evaluation procedures for that purpose. With 
respect to pipeline segments with unknown material toughness, the 
proposed crack evaluation procedures would require the operator to use 
conservative toughness values to evaluate predicted failure pressures 
in response to discovered crack anomalies and the threat of cracks. 
PHMSA proposes to define a ``predicted failure pressure'' as the 
calculated pipeline anomaly failure pressure based on the use of an 
appropriate engineering evaluation method for the type of anomaly being 
assessed. A predicted failure pressure does not include a safety 
factor, and PHMSA believes defining ``predicted failure pressure'' will 
help bring clarity to the regulations and improve compliance.
---------------------------------------------------------------------------

    \95\ Material toughness is the ability of a material to absorb 
energy and plastically deform without fracturing. Technical 
evaluations, including anomaly evaluations, require material 
toughness as an input. If material toughness is low, then the safe 
pressure of the anomaly will also be low.
---------------------------------------------------------------------------

    PHMSA also believes that operators of pipeline segments with 
certain seam attributes should not be allowed to manage class location 
changes with an IM alternative. Even the current and most state-of-the-
art ILI technology, with respect to evaluating seams, is not yet 
reliable enough to warrant including such pipeline segments in this 
NPRM. PHMSA notes that, at this time, ILI tools cannot reliably 
identify or differentiate

[[Page 65161]]

LF-ERW, HF-ERW, or lap-welded seam pipe. The pipeline would need to be 
excavated to observe pipe seam types and use appropriate destructive or 
non-destructive methods. Therefore, the proposed rule would not allow 
the use of the proposed IM alternative for pipeline segments with DC, 
LF-ERW, EFW, or lap-welded seams; or pipe with a longitudinal joint 
factor below 1.0.

H. Eligibility for Pipe With Significant Corrosion

1. Summary of ANPRM Questions 4a(iv) and 4a(v)
    In question 4 of the ANPRM, PHMSA requested comments on whether 
operators should be eligible to use IM to manage class location changes 
if the pipeline segment has experienced corrosion greater than 40 
percent of wall thickness,\96\ or whether operators should replace such 
segments. PHMSA also requested comments regarding whether anomalies in 
pipeline segments in an IM-managed class location change segment should 
use similar repair criteria as subpart O, and whether the current class 
location-specific design factor was appropriate or if it should be 
increased for a Class 1 to a Class 3 location change.
---------------------------------------------------------------------------

    \96\ Corrosion greater than 40 percent of wall thickness is 
considered significant. This threshold is consistent with PHMSA's 
typical class location change special permit conditions.
---------------------------------------------------------------------------

2. Summary of Comments
    The California Public Advocates Office commented that pipelines 
with significant corrosion should be replaced and should not be 
eligible for an IM alternative. It also suggested that PHMSA codify a 
definition of ``significant corrosion.''
    The Associations, pipeline operators, and an individual commenter 
agreed that the current IM regulatory measures and those proposed in 
the 2016 Gas Transmission NPRM would identify ``significant corrosion'' 
through integrity assessments, and those areas would be remediated 
accordingly. In addition, the Associations noted that the GPAC and 
PHMSA discussed an appropriate response to wall loss anomalies during 
the March 2018 GPAC meeting.
    Further, the Associations and supporting operators commented that 
70 percent of corrosion incidents occurred on pipeline segments that 
were not previously assessed with ILI, which they suggested is evidence 
that the current industry practice to remediate corrosion anomalies 
based on ASME B31.8S for those lines that are assessed is an effective 
practice.
    TransCanada Corporation proposed that anomalies, including 
corrosion anomalies, ``should be repaired to criteria greater than or 
equal to MAOP times the reciprocal of the design factor of the 
installed pipe.'' \97\
---------------------------------------------------------------------------

    \97\ An example would be a pipeline segment in a Class 1 
location with a Sec.  192.111 design safety factor of 0.72. The 
reciprocal of 0.72 would be 1.39 (1/0.72), which is a safety factor 
of 39 percent over MAOP.
---------------------------------------------------------------------------

3. PHMSA Response
    Based on the input provided and PHMSA's experience with special 
permits and incident investigations, PHMSA proposes to allow operators 
with pipe with past corrosion to use the IM alternative for Class 1 to 
Class 3 location changes. ILI technology for the detection of corrosion 
metal loss is very mature, and PHMSA believes it is reliable to manage 
the threat of corrosion in pipeline segments that have changed from a 
Class 1 to a Class 3 location if operators perform a corrosion 
assessment properly and validate the results. However, pipeline 
segments would not be eligible if they do not meet the requirements of 
Sec.  192.463 and need linear anodes to maintain adequate levels of CP 
due to poor coating conditions.
    To help ensure pipeline safety, PHMSA proposes enhanced repair 
criteria that would be performed in addition to the repair criteria for 
HCAs in subpart O and would be implemented if operators manage a Class 
1 to Class 3 location segment through IM. This repair criteria would be 
consistent with the repair criteria per the typical class location 
change special permit conditions and includes immediate repair 
conditions \98\ for certain anomalies that are at or near the point of 
failure. The repair criteria would also contain ``scheduled'' 
conditions that would require an operator to repair them within 1 year. 
These scheduled repairs would be for anomalies that are not an 
immediate threat to integrity but that would need to be repaired 
promptly before they grew further. PHMSA also proposes ``monitored'' 
conditions that are not severe enough to need prompt repair but that 
the operator would have to monitor further. The enhanced repair 
criteria would not only apply to the pipeline segment that has changed 
from a Class 1 to a Class 3 location, but would also apply to the 
surrounding Class 2, Class 3, and Class 4 locations contained within 
the in-line inspection segment (i.e., the segment of pipe between the 
closest upstream launcher and downstream receiver that contains the 
Class 1 to Class 3 location segment). PHMSA believes that these 
enhanced repair criteria are necessary for pipe around the Class 1 to 
Class 3 segment because it is likely that there would be nearby 
populations that could be affected by an incident involving the in-line 
inspection segment. Regarding pipe segments with corrosion, 
implementing these enhanced repair criteria would manage pipeline 
segments with prior significant corrosion appropriately, which is 
needed to compensate for operators not installing new pipe to Class 3 
design standards in the changed class location.
---------------------------------------------------------------------------

    \98\ Per ASME B31.8S, section 7.2, an ``immediate'' condition is 
one where an indication shows a defect is at a failure point. As 
such, PHMSA believes that any indication of a pipe that is at the 
point of failure needs to be addressed immediately. In addressing 
``immediate'' conditions, operators must reduce operating pressure 
and immediately remediate the anomaly.
---------------------------------------------------------------------------

    PHMSA is also proposing to exclude those pipeline segments that are 
not transporting distribution customer-quality gas from the IM 
alternative proposed in this rulemaking due to the impact contaminates 
have on corrosion. Such a proposal would prevent Class 1 to Class 3 
location segments that transport gas with deleterious contaminates from 
being transported in segments near areas with higher populations. This 
criterion would also exclude pipeline segments transporting gas with 
free-flowing water or hydrocarbons, gas with higher levels of hydrogen 
sulfide (sour gas), gas with higher levels of carbon dioxide, or gas 
with unacceptable water content, specifically, as these segments would 
be at a higher risk of internal corrosion. Further, contaminants like 
hydrogen sulfide and carbon dioxide would be asphyxiation risks if a 
Class 1 to Class 3 location segment carrying significant percentages or 
volumes of these gases leaked or ruptured in a populated area.
    Regarding TransCanada's comment, PHMSA is not proposing to require 
operators repair the reciprocal of the design factor of the pipe. PHMSA 
is proposing to require operators repair anomalies based on a 1.39 
predicted failure pressure, which is the reciprocal of the 0.72 design 
factor for class 1 pipe, and a wall loss of 40 percent of the pipe wall 
thickness.

I. Eligibility for Damaged Pipe, Dented Pipe, or Pipe That Has Lost 
Ground Cover

1. Summary of ANPRM Question 4a(vi)
    In question 4 of the ANPRM, PHMSA requested comments on whether 
operators should be eligible to use IM to manage class location changes 
if the pipeline segment has been damaged, dented, or has lost ground 
cover due to

[[Page 65162]]

third-party excavation or environmental factors.
2. Summary of Comments
    Regarding environmental factors, the Associations noted that 
operators are already required to conduct patrols with increasing 
frequency in Class 3 and Class 4 areas, and that the 2016 Gas 
Transmission NPRM, if finalized, will require operators to implement 
additional inspections following extreme weather events. Such events 
are the most likely cause of a sudden change in the depth of cover. The 
commenters suggested these existing and pending requirements are 
sufficient to monitor depth of cover changes to ensure pipeline safety, 
regardless of whether a class change has occurred.
    An individual citizen commented that damaged pipe should be 
addressed as detailed in subpart O.
3. PHMSA Response
    PHMSA does not propose to limit the eligibility of pipeline 
segments that have been damaged, dented, or have lost ground cover. ILI 
technology for the detection of dents is very mature, and PHMSA 
believes it is reliable to manage the threat of dents and mechanical 
damage in conjunction with the proposed additional repair criteria and 
existing dent repair criteria for HCAs in subpart O for pipeline 
segments where the class locations have changed from Class 1 to Class 
3. PHMSA also added additional prescriptive P&M actions in the proposed 
provisions, including the addition of line markers or an increase in 
the depth of cover, to address cases where a pipeline segment that has 
changed class location from a Class 1 to a Class 3 location has 
experienced a reduction in the depth of cover.

J. Eligibility Factors Based on Diameter, Operating Pressure, or 
Potential Impact Radius Size

1. Summary of ANPRM Question 10
    In question 10 of the ANPRM, PHMSA requested comments on whether 
operators should be eligible to use IM to manage class location changes 
based on the pipeline segment's diameter, operating pressure, or PIR 
size.
2. Summary of Comments
    Pipeline industry operators and trade associations contended that 
applying diameter, pressure, or PIR limits are not necessary for 
determining the eligibility of pipeline segments for using IM 
principles in place of the existing class location requirements, 
specifically noting that there is currently no technical standard or 
regulation that limits an operator's decision-making based on the PIR 
size, and that the intent of the PIR concept was not to limit where 
integrity assessments could be applied.
    GPA Midstream, in a comment that was echoed by other operators, 
stated that a ``one size fits all'' approach is not appropriate and 
suggested each operator should be allowed to determine the appropriate 
IM measures and actions to ensure safe asset management. It further 
suggested PHMSA should focus on ensuring operators appropriately apply 
IM measures.
    NAPSR stated that any allowances or exceptions to the current 
regulations should be determined on a case-by-case basis. It suggested 
PHMSA should continue to encourage operators to operate pipelines at 
lower stresses, but operators that install pipe that is rated for a 
higher class location than what currently exists should not be 
punished.
    The California Public Advocates Office suggested that PHMSA 
consider more conservative requirements for any IM-based class location 
change management based on the pipeline segment's PIR and that PHMSA 
should host a workshop to determine appropriate values or actions. It 
also suggested PHMSA consider looped, co-located pipelines as 
additional factors for any PIR-based adjustments.
    An individual citizen noted that while diameter and pressure 
limitations are not necessary for pipeline segments where operators 
would use the IM alternative for managing class location changes, PHMSA 
should impose stricter repair criteria on those segments. The commenter 
also noted that immediate repair condition requirements are specified 
in the current regulations, and remediation requirements, if performed 
properly, for all areas, should provide safety beyond the next 
assessment.
3. PHMSA Response
    PHMSA acknowledges that the PIR and class location concepts are 
both used to identify physical locations at which higher consequences 
could result from a pipeline incident by virtue of higher population 
density.\99\ PHMSA believes that, for the purposes of managing class 
location changes, adding PIR-based exclusion criteria would be 
unnecessary. PHMSA believes the requirements it has proposed for 
pipeline segments where the class location has changed from a Class 1 
to a Class 3 location are appropriate for all Class 3 locations 
regardless of the PIR at that location. Therefore, PHMSA is not 
proposing to limit eligibility or impose more stringent requirements 
based on pipe diameter, operating pressure, or PIR.
---------------------------------------------------------------------------

    \99\ Per Sec.  192.903, a PIR means the radius of a circle 
within which the potential failure of a pipeline could have 
significant impact on people or property. PIR is used to determine 
whether an area is an HCA per the HCA definition at Sec.  192.903. 
If, for the purposes of determining an HCA, a PIR in a certain class 
location is greater than 660 feet and the area within the potential 
impact circle contains 20 or more buildings intended for human 
occupancy or contain an identified site, as that term is defined at 
Sec.  192.903, then the area is an HCA.
---------------------------------------------------------------------------

    Furthermore, while PHMSA appreciates the feedback regarding 
changing the method for determining PIR and class location to include 
additional factors such as, looped, co-located pipelines, but this 
comment is outside the scope of this NPRM.
    PHMSA considered the suggestion of more stringent repair criteria 
and included such criteria, in addition to the repair criteria in 
subpart O, for all Class 1 to Class 3 location segments operators would 
choose to manage with the IM alternative in this NPRM. The more 
stringent repair criteria that PHMSA proposes in this rule are designed 
to provide equivalent integrity compared to replacement pipe where a 
class location has changed from a Class 1 to a Class 3 location. 
Existing pipe in these locations is more likely than not to be pre-
Code, vintage pipe where the steel pipe properties do not have the 
toughness properties necessary to mitigate ruptures versus leaks when 
the pipe is corroded, dented, or has any cracking in the pipe body or 
pipe seam.

K. Codifying Current Special Permit Conditions

1. Summary of ANPRM Questions 6 and 6a
    In question 6 of the ANPRM, PHMSA requested comments on whether it 
should codify any or all the current special permit conditions for 
class location changes,\100\ asking whether doing so would satisfy the 
need for alternative approaches. PHMSA also asked what special permit 
conditions could be codified to provide regulatory certainty and 
additional public safety in higher-population areas.
---------------------------------------------------------------------------

    \100\ Examples of typical PHMSA class location special permit 
conditions can be found at https://primis.phmsa.dot.gov/classloc/documents.htm.
---------------------------------------------------------------------------

2. Summary of Comments
    NAPSR and the PST commented that, if the current, typical special 
permit requirements are codified, they should be the minimum guidelines 
and should require multiple tool type assessments, an increased 
inspection frequency, more stringent remediation requirements, and 
enhanced damage prevention activities. They also recommended that PHMSA

[[Page 65163]]

require expedited timeframes and more restrictive remediation criteria 
specific to each class location.
    The Associations, GPA Midstream, and operators commented that the 
current special permit conditions were not designed for broad 
application and should not be codified as written. The Associations 
stated that no additional requirements beyond those proposed in the 
2016 Gas Transmission NPRM were necessary for operators to use IM to 
manage pipeline segments properly where the class location has changed. 
TransCanada Corporation added that implementing these ``broad-brush'' 
conditions would not allow for segment-specific risk considerations, 
which is the basis of an IM approach. GPA Midstream asserted that there 
are no indications the current special permit conditions would satisfy 
statutory considerations in a rulemaking proceeding, or that the cost 
of compliance is justified by the level of public safety benefit.
    An individual citizen stated that certain aspects of current 
special permits are outdated given technological advancements and 
regulatory updates in the 14 years since the initial criteria for 
considering waivers was published. This citizen suggested that class 
location changes from a Class 1 to a Class 3 location should be treated 
as a change in land use, and the pipe in question should be considered 
an identified site, thus triggering HCA requirements.\101\
---------------------------------------------------------------------------

    \101\ Under the current IM regulations at Sec.  192.903, an 
``identified site'' means ``one of the following 3 sites: (a) An 
outside area or open structure that is occupied by 20 or more 
persons on at least 50 days in any 12-month period. The days need 
not be consecutive. Examples include, but are not limited to, 
beaches, playgrounds, recreational facilities, camping grounds, 
outdoor theaters, stadiums, recreational areas near a body of water, 
or areas outside a rural building such as a religious facility. (b) 
A building that is occupied by 20 or more persons on at least 5 days 
a week for 10 weeks in any 12-month period. The days and weeks need 
not be consecutive. Examples include, but are not limited to, 
religious facilities, office buildings, community centers, general 
stores, 4-H facilities, or roller skating rinks. (c) A facility 
occupied by persons who are confined, are of impaired mobility, or 
would be difficult to evacuate. Examples include, but are not 
limited to, hospitals, prisons, schools, day-care facilities, 
retirement facilities, or assisted-living facilities.''
---------------------------------------------------------------------------

3. PHMSA Response
    PHMSA agrees with certain commenters that including Class 1 to 
Class 3 location segments in operator IM programs in accordance with 
subpart O is appropriate for allowing operators to use IM to manage 
class location changes. However, PHMSA also believes that simply 
requiring operators to implement IM on pipeline segments where the 
class location has changed from a Class 1 to a Class 3 location, 
without undertaking additional safety requirements, does not provide an 
equivalent level of safety as the current system of pipe replacement, 
pressure testing, or pressure reduction. Thus, to provide public safety 
where the pipe has not been upgraded to current Class 3 location 
standards when the class location changes, PHMSA proposes to require 
that operators implement IM in accordance with subpart O and supplement 
that IM with additional standards that have been successfully applied 
in previous special permits. These additional activities would include 
close interval surveys (CIS),\102\ the installation of CP test 
stations, and interference surveys to ensure the maintenance of 
coatings and reduce the numbers of immediate and scheduled repairs. 
These additional measures address specific threats to pipelines, 
including corrosion, and are necessary to account for the lack of 
additional pipe wall thickness in lieu of pipe replacement. Without 
thicker-walled pipe, these conditions will help to provide for a 
consistent level of safety over the lifecycle of the pipeline.
---------------------------------------------------------------------------

    \102\ CIS are a series of closely and properly spaced pipe-to-
electrolyte potential measurements taken over the pipe to assess the 
adequacy of cathodic protection or to identify locations where a 
current may be leaving the pipeline that may cause corrosion and for 
the purpose of quantifying voltage (IR) drops other than those 
across the structure electrolyte boundary, such as when performed as 
a current interrupted, depolarized or native survey.
---------------------------------------------------------------------------

    PHMSA is also proposing specific repair criteria for the Class 1 to 
Class 3 location segment that would be applied in addition to the 
existing repair criteria in subpart O. This additional repair criteria 
would also be applicable to the Class 2, Class 3, and Class 4 locations 
located within the entire in-line inspection segment. With these 
proposed changes, operators would categorize more anomalies as 
``immediate'' conditions, which would help ensure an expedited repair 
schedule. Furthermore, the updated repair requirements of this proposal 
essentially provide an approximately 26 percent increase in safety 
factor for the pipe strength given that the NPRM would require the 
repair of conditions reaching a 1.39 safety ratio whereas the current 
IM regulations require the repair of conditions reaching a 1.1 safety 
ratio. The proposed repair criteria will also help to ensure safety 
where there is thinner-walled pipe in the ground by requiring the 
repair of anomalies where there is 40 percent of pipe wall loss, rather 
than the 80 percent that currently exists under IM.
    Based on PHMSA's experience with existing Class 1 to Class 3 
location change special permits and the feedback from the ANPRM, PHMSA 
proposes to incorporate the following special permit conditions into 
the regulations for those pipeline segments changing from a Class 1 to 
a Class 3 location that operators will manage using the IM alternative. 
PHMSA proposes to require the following conditions to help ensure that 
the level of safety achieved is equivalent to pipe replacement for the 
life of the pipeline:
     Perform an initial integrity assessment within 24 months 
of the Class 1 to Class 3 location change, which is consistent with the 
requirements at Sec. Sec.  192.609 and 192.611.
     Use high-resolution ILI metal loss and deformation, 
electromagnetic acoustic transducer (EMAT), and inertial measurement 
unit (IMU) tools where appropriate for the pipeline integrity threat, 
which would be consistent with the current IM requirements. To help 
ensure that operators address cracking threats and ground movement, if 
an operator chooses not to conduct EMAT or IMU inspections on pipeline 
segments with a history of cracking or pipe movement, then the operator 
would be required to notify PHMSA in accordance with Sec.  192.18.
     Perform periodic reassessments using ILI, which would be 
consistent with the current IM requirements.
     Validate ILI tool results, which would be consistent with 
the current IM requirements.
     Repair anomalies using more stringent repair criteria than 
the existing repair criteria under the current IM requirements, which 
will maintain equivalent safety, compared to pipe replacement, over the 
life of the pipeline.
     Replace pipeline segments: (1) With discovered cracks that 
exceed 20 percent of wall thickness, or (2) with a predicted failure 
pressure less than 100 percent of SMYS, or (3) with a predicted failure 
pressure less than 1.5 times MAOP, or (4) that could fail in the 
brittle failure mode. This requirement is based on PHMSA research and 
API's Recommended Practice 1176, ``Assessment and Management of 
Pipeline Cracking'' and would go beyond the current IM repair criteria.
     Until the pipeline segment can be replaced per the 
requirement above, cracks must be remediated using additional crack 
repair criteria. This requirement is consistent with the current IM 
requirements.
     Evaluate for pipe cracking, such as SCC, when the pipe is 
exposed for IM

[[Page 65164]]

or the proposed regulation activities and is found with disbonded or 
previously repaired coating. Pipe excavated for damage prevention 
program activities under Sec.  192.614 would not require pipe cracking 
inspections so as not to delay those activities. This treatment is 
consistent with the current IM requirements.
     Conduct close interval surveys (CIS) at intervals at least 
once every 7 years and not exceeding 90 months. Operators should be 
performing these surveys under the IM regulations, so this condition 
would be consistent with that requirement.
     Ensure that at least one CP pipe-to-soil test station is 
within the pipeline segment that changed from a Class 1 to a Class 3 
location, with a maximum spacing interval of one-half mile. This 
condition will meet the current requirements at subpart I for corrosion 
control.
     Install line-of-sight markers at defined points, which is 
consistent with elements of the current requirement at Sec.  192.707 
and PHMSA's current special permit conditions for class location change 
management. Line-of-sight markers would be line markers where each 
marker is visible from at least one other line-of-sight marker.
     Conduct interference surveys, which would be consistent 
with the current requirements at Sec.  192.473. If operators are unable 
to receive the necessary permitting authority to complete surveys in 
time, they can apply to PHMSA for a special permit regarding that 
issue.
     Maintain depth of cover to Class 1 location standards or 
remediate areas with reduced cover. This condition keeps the original 
design standards for the affected pipe segment so as to avoid imposing 
retroactive design standards, which PHMSA cannot do.
     Conduct right-of-way patrols on a monthly basis and 
leakage surveys on a quarterly basis. This condition will help to 
ensure, on a more consistent basis, that the pipe segment is not 
damaged by third-party entities and that hazardous leaks do not occur 
where there are substantial populations. These requirements will also 
provide safety in that they are more stringent than the current Class 3 
requirements.
     Clear shorted casings within 1 year, which operators are 
already required to do in accordance with Sec.  192.467.
     Document and maintain records, for the life of the 
pipeline, of the actions required by the Class 1 to Class 3 location 
requirements. This documentation requirement is consistent with 
requirements in the recently published 2019 Gas Transmission Final 
Rule.
    PHMSA requests comment as to whether any of these P&M measures 
could be modified or otherwise eliminated, and if so, what the impacts 
of safety would be and if safety could be maintained, what alternative 
approach would maximize net benefits to society.
    Per PHMSA's data over the last decade, there have been 699 
``significant'' incidents occurring on gas transmission pipelines, 
which are defined as ones involving (1) a fatality or in-patient 
hospitalization, (2) $50,000 or more in property damage, or (3) 
incidents where over 3 million cubic feet of gas are lost. Of these 
incidents, 269 were caused by material, equipment, or weld failures (38 
percent); 165 by corrosion (24 percent); 93 by excavation damage (13 
percent); 61 by natural force damage (9 percent); 42 by other outside 
force damage (6 percent); 40 by incorrect operation (6 percent); and 29 
by other causes (4 percent).
    In many ways, the conditions that are consistent with IM outlined 
above are meant to mitigate many of these incident causes, including 
material failure and corrosion. Performing recurring integrity 
assessments helps operators understand the current condition of their 
pipe and reveals anomalies that, if left unchecked, could result in a 
serious rupture and incident.
    Some of the additional surveys PHMSA is proposing to require are 
additional safeguards against corrosion threats. In the absence of new, 
thicker-walled pipe in a Class 3 location, performing CIS and 
interference surveys, as well as ensuring the proper placement of CP 
test stations, will help to provide assurance that a pipeline segment 
will not rapidly corrode prior to being discovered before the next 
integrity assessment.
    PHMSA is proposing conditions for line-of-sight markers and depth 
of cover because these serve as mitigation measures for potential 
accidents involving excavation damage. Excavation damage is more likely 
to happen in more populated areas, as there are typically more 
utilities near pipelines and more people digging around those 
utilities. A strike from excavation equipment can cause a rupture, 
severely dent the pipe, or damage the pipe's protective coating. Even 
though PHMSA is not proposing to require more stringent depth-of-cover 
conditions beyond those designed for Class 1 locations, PHMSA believes 
the additional line-of-sight markers combined with additional 
patrolling and leak survey requirements will provide a commensurate 
level of safety compared to the Class 3 depth of cover requirements.
    PHMSA proposed including a condition for operators to clear shorted 
casings because shorted casings were major contributors in two major 
pipeline incidents. On December 14, 2007, a 30-inch gas transmission 
pipeline owned by Columbia Gulf Transmission Company ruptured near 
Delhi, LA, killing a man and injuring another man who were driving 
nearby on Interstate 20. On December 11, 2012, a 20-inch gas 
transmission pipeline operated by Columbia Gas Transmission Company 
ruptured about 100 feet west of Interstate 77 near Sissonville, WV. 
Three houses were destroyed by the fire, and several other houses were 
damaged. Interstate 77 was closed in both directions because of the 
fire and resulting damage to the road surface, causing delays to 
travelers and commercial freight. Both accidents were attributable to 
shorted casings that had not been properly addressed.
    In addition to the above special permit conditions, PHMSA is also 
proposing to require operators use SCADA systems and install and use 
remote-control or automatic shutoff block valves upstream and 
downstream of the Class 1 to Class 3 segment. PHMSA believes that the 
additional P&M measures proposed in this NPRM, along with the higher 
standards for repairs and remediation, make an increased inspection 
frequency suggested by certain commenters unnecessary.

L. Additional Preventive and Mitigative Measures Needed for an 
Integrity Management Option for Class Location Change Management

1. Summary of ANPRM Questions 9, 9a, and 9b
    In question 9 of the ANPRM, PHMSA requested comments on whether 
operators would need to install additional pipeline safety equipment, 
P&M measures, or more conservative prescribed standard pipeline 
predicted failure pressures if using IM principles to manage pipeline 
segments where the class location has changed from a Class 1 to a Class 
3. More specifically, PHMSA requested comments on whether the 
regulations should require rupture-mitigation valves or SCADA systems 
on IM-managed class location change pipeline segments.
2. Summary of Comments
    TransCanada Corporation proposed operators should perform site-
specific assessments to determine the

[[Page 65165]]

appropriate safety equipment or mitigative measures to implement. GPA 
Midstream supported this concept in its comments.
    NAPSR stated that if PHMSA does not require pipe replacement, PHMSA 
should specify additional safety and P&M measures. They suggested that 
rupture-mitigation valves or equivalent technology should be required 
if an operator does not replace pipe to manage a class location change, 
and SCADA systems should be required for large and complex pipeline 
systems. Further, NAPSR stated that IM should be a system-wide program, 
``not a substitute'' for the additional safety provided by class-
location requirements. Similarly, NAPSR also stated that pipe 
replacements are preventive measures while valves are mitigative 
measures, arguing the level of safety between the two is not equal.
    Broadly speaking, the Associations and multiple operators stated 
that the requirements proposed in the 2016 Gas Transmission NPRM are 
more than sufficient in ensuring safety, and it is unnecessary for 
PHMSA to require additional P&M measures for pipeline segments changing 
class locations. Class location change requirements, they asserted, are 
just a few of many regulations that are applicable to any given 
pipeline segment. MidAmerican Energy Company, for instance, stated that 
the requirements proposed in the 2016 Gas Transmission NPRM are 
adequate for covering class location changes, and no additional safety 
equipment or P&M measures should be required beyond those regulations.
    Further, the Associations and GPA Midstream commented that the 
installation of rupture-mitigation values has not been addressed 
historically in special permits nor any previous class location 
regulatory discussions. GPA Midstream did not feel that this would 
achieve the intended purpose of class location change requirements, and 
PHMSA has not provided evidence or discussion in support of this 
requirement.
    Similarly, the Associations commented that SCADA systems have not 
been required compliance items in special permits historically, and 
most gas transmission pipelines already have SCADA systems in place. 
They argued that this requirement seems unnecessary given that PHMSA 
has not provided evidence or discussion in support of this requirement.
    GPA Midstream noted that, as currently allowed in the IM 
regulations, the operator should be able to determine the necessity of 
a SCADA system. It noted that for short pipelines or simple systems, it 
may be impractical. Other operators echoed this comment, noting that if 
a site-specific assessment determined that a SCADA system would be 
beneficial, the operator should have the option to add it.
    Other operators provided a range of comments regarding SCADA 
systems, from supporting the viewpoint that impacted segments should be 
monitored with SCADA systems to general data indicating that large 
portions of their individual pipeline systems were managed with SCADA 
systems.
    An individual citizen commented that the regulations currently do 
not require newly installed or previously installed pipe to have 
additional safety equipment or P&M measures. The commenter suggested 
that allowing operators to use ILI or similar technologies in a 
rigorous IM program would allow operators to know the pipeline 
segment's condition and remediate it appropriately, which would 
preclude the need for prescriptive P&M measures. In addition, this 
citizen commented that rupture-mitigation valves have limited efficacy 
and are not proven to be reliable technology. The commenter also noted 
that ``systems designed to react to ruptures will not be useful in 
detecting leaks.'' Further, the commenter noted that SCADA systems 
should not be required, as they only mitigate the consequences of an 
incident and will not prevent a rupture.
3. PHMSA Response
    PHMSA has observed that certain operators have not adopted 
additional P&M measures when implementing the IM regulations under 
subpart O.\103\ As a result, PHMSA has determined that proposing 
additional prescriptive mitigative measures are appropriate, including 
to install remote-control or automatic shutoff valves upstream and 
downstream of the segment changing from a Class 1 to a Class 3 
location. While the installation of rupture-mitigation valves has not 
previously been required when operators replace pipe, using IM to 
manage class locations that change from Class 1 to Class 3 would be 
fundamentally different in that operators would not be putting stronger 
pipe in the ground, thereby making additional safety measures 
necessary.
---------------------------------------------------------------------------

    \103\ For instance, following the PG&E incident at San Bruno, 
CA, PG&E rapidly installed automatic shutoff valves where possible 
and stated there was sufficient basis to deploy such valves. 
However, company documents from 2006 stated that the company had 
concluded that most of the damage from a rupture would take place in 
the first 30 seconds before shut-off valves could stop the flow of 
gas and declined to install the valves in the area.
---------------------------------------------------------------------------

    As proposed, the rupture-mitigation valve spacing would be 
consistent with existing Class 1 location mainline valve spacing 
requirements, with the explicit intent that this approach would not 
require the addition of any mainline valves, and assuming operators 
currently comply with the existing valve spacing requirements. However, 
if the valves in place are manual valves, PHMSA proposes that operators 
upgrade those valves to be operated by remote control or automatic 
shutoff as an additional mitigative measure. This approach would be 
consistent with NTSB recommendation P-11-11 to require automatic or 
remote control valves in HCAs and Class 3 and Class 4 locations,\104\ 
which was issued after the 2010 PG&E incident in San Bruno, CA.
---------------------------------------------------------------------------

    \104\ https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR1101.pdf. ``Pacific Gas and Electric Company, Natural Gas 
Transmission Pipeline Rupture and Fire, San Bruno, CA, September 9, 
2010.''
---------------------------------------------------------------------------

    PHMSA is proposing that any remote-control or automatic shutoff 
valves installed in accordance with the additional P&M measures must be 
set so that, based on operating conditions, they will fully close 
within a maximum of 30 minutes following rupture identification. 
PHMSA's proposed 30-minute valve closure time would be consistent with 
conditions it has required operators to meet in special permits for 
class location changes. In addition, PHMSA requests comment on whether 
additional requirements and standards are needed for the installation 
of automatic shutoff valves in place of remote-control valves for the 
purposes of this rulemaking. If installing automatic shutoff valves in 
accordance with this proposed requirement, operators would be required 
to review their procedures and results for determining valve shutoff 
times on a calendar year basis, not to exceed 15 months. This approach 
is consistent with current requirements in Sec.  192.745 where 
operators must inspect and partially operate each transmission line 
valve that might be required during any emergency, and take prompt 
remedial action to correct any valve found inoperable.
    As noted by industry, most operators already have a SCADA system in 
place. Therefore, PHMSA is proposing that operators must have a SCADA 
system to implement IM measures for managing Class 1 to Class 3 
location changes. A SCADA system will help operators detect leaks and 
other pressure loss situations more rapidly. In addition, PHMSA is 
proposing that remote-control valves and automatic shutoff

[[Page 65166]]

valves installed per this NPRM must be controlled and monitored by a 
SCADA system and promptly closed to isolate the pipeline segment should 
a rupture occur. As such, and similar to how pipelines with 
exclusionary conditions would be handled, operators without a SCADA 
system could apply for a special permit to implement IM in lieu of pipe 
replacement when class locations change.

M. Traceable, Verifiable, and Complete Records for Supporting Class-
Location-Change Integrity Management Measures

1. Summary of ANPRM Questions 5, 5a, and 5b
    In question 5 of the ANPRM, PHMSA requested comments on introducing 
requirements for TVC records, including what records would be required, 
and how and when they could be obtained, to support any IM measures 
that would be performed to manage class location changes. More 
specifically, PHMSA asked whether necessary TVC record should include 
pipe properties, including yield strength, seam type, and wall 
thickness; coating type; O&M history; leak and failure history; 
pressure test records; MAOP; class location; depth of cover; and 
ability to be in-line inspected.
2. Summary of Comments
    NAPSR, the PST, and the California Public Advocates Office 
supported requiring TVC records for segments where operators would like 
to manage class location changes by using IM measures. NAPSR also 
asserted, and PST agreed, that historically poor recordkeeping 
practices should be considered a potential indicator of risk, as 
mapping issues have often been found to be latent conditions or 
indicators of higher risk in pipeline accidents.
    More specifically, the California Public Advocates Office supported 
the idea that PHMSA require in the regulation TVC records for yield 
strength, seam type, and wall thickness, and it suggested adding 
outside diameter as an additional pipe property to consider. It stated 
that records, if available, should be obtained by the operator within 2 
years of the class location change. If these records were unavailable, 
the California Public Advocates Office supported allowing an operator 
to request a special permit from PHMSA.
    NAPSR and the PST stated that, given that records can be acquired 
or created if necessary (i.e., through a pressure test, pipe 
specification verification, and lab tests), if an operator does not 
have the appropriate records, PHMSA should not allow an operator to use 
IM measures to manage class location changes. Both NAPSR and the PST 
noted that operators should be leveraging ILI technology to create 
records needed for regulatory compliance by, at a minimum, employing 
tools that can effectively identify corrosion, dents, gouges, cracks, 
and interactive defects.
    The Associations, GPA Midstream, and multiple operators requested 
that TVC records only apply to MAOP verification, and that a lack of 
records should not make a pipeline segment ineligible for using IM to 
manage class location changes. They also noted that, should TVC records 
not be available for pipeline segments undergoing a class location 
change, the 2016 Gas Transmission NPRM provides a way for operators to 
obtain those records and take appropriate safety options within 24 
months of the class location change. Further, they stated that 
additional records may be required for ILI-identified anomaly analysis 
and will be collected.
    Kinder Morgan added that the TVC standard is not intended for many 
records used in IM processes. TransCanada Corporation stated that while 
TVC records are helpful and would improve site-specific assessments, 
they are not critical for an operator to perform IM measures given that 
adequate testing or conservative assumptions may be employed.
    An individual citizen commented that for IM measures specifically, 
ILI technology implementation, design records, and pressure test 
records are necessary for anomaly assessment. As stated by this 
citizen, pressure test information is only required for assessing 
longitudinal seam anomalies and is only valuable if the test was 
conducted to at least 1.25 times MAOP. The commenter also asserted that 
record ``completeness'' should be determined based on the required use 
of the information. Given that design pressure is calculated with 
outside diameter, wall thickness, and SMYS, records that supply these 
values should be considered ``complete'' if the data is used to 
calculate design pressure, according to this individual. Finally, the 
commenter noted that coating type is not nearly as important as coating 
condition, and depth of cover is a practical concern, especially in 
agricultural areas, yet is not required in Sec.  192.611 and was not 
required prior to the promulgation of the natural gas regulations in 
1970.
3. PHMSA Response
    PHMSA agrees with certain commenters that documentation and 
recordkeeping are very important and has included a proposed 
requirement that operators keep records of the pipeline assessments, 
surveys, remediations, maintenance, analyses, and any other action 
implemented to comply with the requirements proposed under this 
rulemaking for managing Class 1 to Class 3 location changes using the 
IM for the life of the pipeline.
    Per this rulemaking, operators would need to have, or otherwise 
obtain, TVC material-properties records (e.g., diameter, wall 
thickness, yield strength, seam type, and coating type) to implement 
the proposed IM alternative for managing a pipeline segment that has 
changed from a Class 1 to a Class 3. These types of material properties 
records are necessary for a PSR-compliant IM program \105\ and MAOP 
determination.\106\
---------------------------------------------------------------------------

    \105\ Operators need TVC records to repair anomalies and for IM 
measures that depend on design properties.
    \106\ TVC records are required for MAOP determination. To be 
TVC, a record must be clearly linked to the original information 
about a pipeline segment or facility; confirmed by other 
complementary, but separate, documents; and finalized by a 
signature, date, or other appropriate marking.
---------------------------------------------------------------------------

    As commenters noted, the 2019 Gas Transmission Final Rule provides 
a mechanism for operators to obtain TVC material property records if 
they are missing, and the 24-month compliance window of this NPRM 
provides operators with adequate time to obtain those records, if 
needed. As specified in the 2019 Gas Transmission Final Rule, if 
operators are missing any material property records needed when 
performing anomaly evaluations and repairs, operators must confirm 
those material properties under Sec. Sec.  192.607 and 192.712(e) 
through (g). Records created in accordance with Sec.  192.607 must be 
maintained for the life of the pipeline and must be TVC; therefore, if 
an operator would need to create material records prospectively to be 
eligible for the IM alternative, those records would be TVC.

N. Data on Class Location Pipe Replacement and Route Planning

1. Summary of ANPRM Questions 7 and 8
    In the ANPRM, PHMSA requested data regarding operators' compliance 
with current class change pipe replacement requirements, including the 
amount of pipe being replaced, the number of distinct locations where 
pipe

[[Page 65167]]

was being replaced, and the associated costs.
    PHMSA also requested comments on whether and to what extent 
operators consult growth and development plans during route planning.
2. Summary of Comments
    PHMSA received various technical data provided by individual 
operators and trade associations regarding the amount of pipe being 
replaced, the number of locations at which pipe was replaced, and the 
associated costs.
    Pertaining to route planning, the responses PHMSA received from 
industry, individuals, and groups alike stated that operators consider 
future building plans along a proposed pipeline route when considering 
both the route and pipe materials. NAPSR asserted that most operators 
are currently defaulting to Class 3 requirements for all newly 
installed pipe. NAPSR also stated concern with allowing operators to 
use IM principles for managing class location changes in that it could 
discourage operators from continuing this conservative practice.
3. PHMSA Response
    PHMSA considered the data it received on class location change pipe 
replacement when developing the PRIA; see that document for further 
discussion on the data received and the subsequent assumptions and 
analysis PHMSA made and performed.
    Regarding operators considering growth and development plans when 
route planning, PHMSA will note that operators must monitor and 
implement class location changes based on the required study 
requirements of Sec.  192.609 and confirm or revise MAOP based on the 
requirements in Sec.  192.611. Pipeline segments that experienced a 
class change before the date of the rule would not be eligible to apply 
the IM approach to managing the class location change, but operators 
could still apply for a special permit to manage these pipeline 
segments with IM.

O. Other Topics--General Comments

    The following relevant comments received were of a general nature 
or did not pertain to questions considered in the ANPRM.
    The PST and multiple individuals from the public requested that 
PHMSA host public meetings and webinars early in the rulemaking process 
to educate the public on the current and proposed class location change 
regulations. The Pipeline Safety Coalition stated that PHMSA doing so 
would facilitate a safety culture based on holistic participation from 
informed parties.
    State representatives from the State of New Jersey's 14th, 15th, 
16th, and 18th legislative districts commented that New Jersey requires 
that intrastate pipelines be constructed to Class 4 location design 
requirements, regardless of population density. They encouraged PHMSA 
to consider adopting New Jersey's stricter intrastate requirements for 
interstate assets.
    The California Public Advocates Office supported PHMSA's effort to 
streamline the current class location regulations as it believed it 
would be advantageous to both operators and regulators. It also 
requested that PHMSA re-evaluate the definition of a Class 4 location 
to include stadiums or concert venues, which would not qualify 
currently but present significant public safety consequences.
    Based on certain aspects of the ANPRM, GPA Midstream expressed 
concern about PHMSA's commitment to making meaningful improvements to 
the class location regulations, stating that PHMSA is suggesting 
``unrelated issues identified in previous advisory bulletins or during 
routine inspections are relevant to the decision of whether to update 
the class location regulations'' and that the agency suggests ``topics 
that are already being addressed in a separate rulemaking proceeding 
should limit an operator's ability to obtain class location relief.'' 
They did, however, support adding more options for an operator to 
address class location changes.
    The Associations and TransCanada Corporation suggested that 
currently issued special permits could be retired when an operator 
demonstrates that all conditions have been satisfied and that the class 
location change is managed to an acceptable level of safety.
    As an additional consideration to the class location change 
regulations, the Associations suggested other regulations that would be 
affected, such as those at Sec.  192.625 for odorization, should be 
adjusted. They specifically requested that PHMSA allow alternative P&M 
measures in lieu of odorization. Further, they also commented that an 
operator using integrity assessments for class location change 
management should also be allowed to uprate their MAOP in accordance 
with subpart K.
    The Associations also requested that PHMSA implement an expedited 
interim process for class location changes, which would allow operators 
to manage class location changes through integrity assessments prior to 
implementation of the final rule. They contend that this regulatory 
update has been in the works for 15 years, and cost efficiencies 
realized by this change would enhance operator ability to fund 
integrity assessment technology development.
    The Associations expressed support for PHMSA including additional 
fields in the annual report to collect information on class location 
designation, integrity assessments, or data on other class change 
management operators use. Furthermore, they requested that PHMSA 
implement annual report changes to replace what they identified as 
excessive reporting and notifications required for special permits.
    Finally, the Associations commented that PHMSA's singular focus on 
pipe stress is misplaced and outdated given that modern integrity 
assessment technology can provide equivalent safety factors to stress-
reducing measures.
1. Response to General Comments
    Regarding the New Jersey State legislators' comment, PHMSA 
recognizes that New Jersey may have more conservative design 
requirements for new intrastate gas transmission pipelines than what is 
being proposed in this NPRM; however, implementing these requirements 
would not support the NPRM focus of managing class location changes 
safely in existing pipelines.
    PHMSA is proposing that segments uprated in accordance with subpart 
K may be allowed to use this proposed rule for class location change 
management, but only if the segment has had a subpart J pressure test 
to at least 1.39 times MAOP \107\ and meets all the requirements of the 
proposed rule, including those regarding records. Segments uprated 
without a subpart J pressure test would be excluded under this proposed 
rule.
---------------------------------------------------------------------------

    \107\ PHMSA acknowledges that Sec.  192.555 allows uprating 
based upon the highest pressure allowed in Sec.  192.619, which 
would require a 1.50 times MAOP for a Class 3 location. Since Class 
1 location pipe would only be tested to either 1.1 or 1.25 times 
MAOP based upon Sec.  192.619, the proposed rule change would 
require a 1.39 times MAOP for uprating the MAOP where operating 
pressures of a segment have been lowered for other existing Class 1 
to Class 3 location changes.
---------------------------------------------------------------------------

    Regarding the comments from TransCanada and the Associations on the 
class location definitions, odorization requirements, and special 
permit ``retirement'' provisions, PHMSA has determined to propose 
alternative requirements to those currently imposed on pipeline 
segments experiencing a change in class location in this NPRM.
    PHMSA is not proposing an expedited interim process for class 
location changes as a part of this NPRM. In the absence of these 
proposed regulatory

[[Page 65168]]

changes, operators can currently apply for a special permit to manage 
class location changes in a similar manner. Part of the intent of this 
NPRM is to codify much of the current special permit process into the 
regulations, thereby providing greater regulatory certainty and a 
streamlined process for class location change management for eligible 
pipe segments.
    PHMSA respectfully disagrees that a singular focus has been placed 
on pipe stress. PHMSA is concerned with every threat to pipeline 
integrity and how they can be remediated to maintain safety. PHMSA also 
disagrees that the reporting requirements for the current special 
permit process are excessive. The special permit process is an optional 
process that operators can opt into. If the requirements are excessive, 
operators can comply with the regulations as they are written. With 
that said, PHMSA may consider revising the annual report as needed when 
finalizing this rulemaking.

IV. Section-by-Section Analysis

Sec.  191.22 National Registry of Pipeline and LNG Operators

    Section 191.22 details events that require a notification to PHMSA. 
PHMSA has proposed the addition of requiring operators to notify PHMSA 
if they use IM to manage pipeline segments that have changed from a 
Class 1 to a Class 3 location. This prompt notification would provide 
PHMSA an opportunity to oversee the operator's implementation of the 
proposed Class 1 to Class 3 location segment regulations.

Sec.  192.3 Definitions

    Section 192.3 provides definitions for various terms used 
throughout part 192. In support of the regulations proposed in this 
NPRM, PHMSA is proposing new definitions for the terms ``Class 1 to 
Class 3 location segment'' and ``in-line inspection segment.'' These 
two terms define the segments to which the requirements of the proposed 
Sec.  192.618 would apply.
    A ``Class 1 to Class 3 location segment'' would be defined as the 
segment of pipe where the class location has changed from a Class 1 to 
a Class 3 location and where the operator intends to confirm or revise 
the MAOP by using the IM alternative in this proposed rulemaking. The 
Class 1 to Class 3 location segment will consist of the pipe that was 
designed to Class 1 specifications, per subpart C, that is in a newly 
identified Class 3 location.
    An ``in-line inspection segment'' would be defined as including all 
pipe upstream and downstream of the Class 1 to Class 3 location segment 
that is between the nearest upstream ILI launcher and the nearest 
downstream ILI receiver and the Class 1 to Class 3 location segment.
    PHMSA is also proposing a definition for ``predicted failure 
pressure'' to provide additional clarification to the regulations. A 
``predicted failure pressure'' would be defined as the calculated 
pipeline anomaly failure pressure based on the use of an appropriate 
engineering evaluation method for the type of anomaly being assessed 
and without any safety factors.

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 to 
reflect other changes adopted in this final rule.
    API Standard 1163, which is already incorporated by reference into 
the regulations for natural gas transmission pipelines at Sec.  192.493 
and for hazardous liquid pipelines at Sec.  195.591, covers the use of 
ILI systems for onshore and offshore gas and hazardous liquid 
pipelines. This standard 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, and it is an umbrella document that provides performance-
based requirements for ILI systems, including procedures, personnel, 
equipment, and associated software.
    In this NPRM, PHMSA is proposing to incorporate this standard by 
reference into the proposed IM alternative at Sec.  192.618(b)(4) to 
require operators validate ILI results to Level 3 in accordance with 
API Standard 1163. Per API Standard 1163, a Level 3 validation is one 
where ``extensive validation measurements are available that allow 
stating the as-run tool performance. Validating to such a level allows 
an operator to establish a direct link between the ILI tool performance 
and the impact it has on IM decisions.'' PHMSA requests comment as to 
whether it should allow operators to validate ILI results to Level 2 or 
Level 3 per API Standard 1163. Per API Standard 1163, a Level 2 
validation is ``where no definitive statement is made about the actual 
tool performance. Although it is possible to state with a high degree 
of confidence whether the tool performance is worse than the 
specification, the approach does not allow one to state with confidence 
that the tool performance is within specification.''
    Further, PHMSA is proposing to incorporate by reference ASME/ANSI 
B31.8S-2004 for proposed Sec.  192.618. B31.8S is specifically designed 
to provide the operator with the information necessary to develop and 
implement an effective IM program utilizing proven industry practices 
and processes. Effective system management can decrease repair and 
replacement costs, prevent malfunctions, and minimize system downtime.

Sec.  192.611 Change in Class Location: Confirmation or Revision of 
Maximum Allowable Operating Pressure

    Section 192.611 prescribes requirements for operators when a change 
in class location has occurred. With the development of the IM 
alternative in proposed Sec.  192.618, conforming changes would be 
needed to this section to specify that an operator may confirm or 
revise the MAOP of a Class 1 to Class 3 segment in accordance with 
proposed Sec.  192.618. A pressure reduction taken in accordance with 
this section and after the effective date of this rule would not 
preclude an operator from implementing an integrity assessment program 
per paragraph (a)(4) of this section at a later date. Further, an 
operator would need to implement such a program prior to any future 
increases of MAOP. For the purposes of this section, operators will not 
be allowed to use pressure reductions taken prior to the effective date 
of the rule for Class 1 to Class 3 locations. Operators who wish to do 
so would be required to apply to PHMSA for a special permit.

Sec.  192.618 Class 1 to Class 3 Location Segment Requirements

    Section 192.618 establishes the proposed conditions an operator 
would implement in its O&M procedures if it chooses to manage pipeline 
segments where the class location has changed from a Class 1 to a Class 
3 through the IM alternative. PHMSA notes that the approach outlined in 
this NPRM would apply only to those pipeline segments that have changed 
class location following the effective date of the rulemaking; 
operators would not be able to use the IM alternative retroactively for 
pipeline segments that have experienced a class location change prior 
to this rulemaking.
    The proposed requirements in this NPRM are based on PHMSA's 
extensive experience with evaluating special permit applications and 
granting special permits that effectively apply specific

[[Page 65169]]

safety requirements on a case-by-case basis.
    Per this proposal, operators would designate the Class 1 to Class 3 
location segment as an HCA, as that term is defined in Sec.  192.903, 
and include the segment in its IM program in accordance with subpart O. 
Operators would also inspect all pipe between the nearest upstream ILI 
launcher and nearest downstream ILI receiver that contains the pipeline 
segment changing from a Class 1 to a Class 3 location when performing 
an ILI assessment of the Class 1 to Class 3 location segment.
    PHMSA has proposed certain conditions, similar to its practice for 
special permits, that would preclude the use of this IM alternative for 
managing class location change segments for pipeline segments with 
certain higher-risk attributes. More specifically, the proposed minimum 
pipe eligibility criteria are based on the previously published 
guidance in the 2004 Federal Register Notice. As outlined in that 
criteria and this NPRM, certain pipeline segments would not be eligible 
for the IM alternative because they are higher risk and warrant a case-
by-case review per the special permit process.
    PHMSA proposes a pipeline segment would be ineligible to use the IM 
alternative if any of the following conditions exist on that segment:
     Pipeline segments that operate above 72 percent SMYS.
     Pipeline segments with bare pipe (i.e., uncoated pipe).
     Pipeline segments with wrinkle bends.
     Pipeline segments that are missing records for diameter, 
wall thickness, grade, seam type, yield strength, and tensile strength.
     Pipeline segments without a hydrostatic test conducted 
with a test pressure of at least 1.25 times MAOP.
     Pipe with DC, LF-ERW, EFW, or lap-welded seams, or pipe 
with a longitudinal joint factor below 1.0.
     Pipe with cracking in the pipe body, seam, or girth welds 
in the segment, or within 5 miles of the segment, that is over 20 
percent of the pipe wall thickness, has a predicted failure pressure 
less than either 100 percent of SMYS or 1.5 times MAOP, or has 
experienced a leak or a rupture due to brittle failure mode. Should a 
pipeline segment changing from a Class 1 to a Class 3 location at any 
time fail the requirements regarding cracking, that segment would no 
longer be eligible for the IM alternative for class location change 
management, and the operator would be required to replace the segment 
within 2 years of the ineligibility determination. Prior to the 
replacement, the enhanced crack repair conditions as detailed below 
would apply.
     Pipeline segments with tape coatings or shrink sleeves, or 
with poor external coating that requires the use of a 100 millivolt 
shift or linear anodes to maintain required levels of CP.
     Pipeline segments that transport gas whose composition 
quality is not suitable for sale to gas distribution customers.
     Pipeline segments that operate under Sec.  192.619 (c) or 
(d).
     Pipeline segments, or portions of pipeline segments, that 
have been denied a class location change special permit in the past.
    This section also contains proposed requirements for operators to 
conduct their initial integrity assessment within 24 months of the 
Class 1 to Class 3 location segment change, which would be consistent 
with existing requirements for the deadline to reconfirm or revise a 
pipeline segment's MAOP when its class location changes; the specific 
ILI integrity assessment methodology, including ILI results validation, 
that operators must use; and additional repair criteria for these 
segments that supplements the existing repair criteria in subpart O.
    For the purposes of ILI tool calibration and validating ILI 
results, an operator may use previously excavated anomalies or recent 
anomaly excavations with known dimensions that were field measured for 
length, depth, and width; externally re-coated; CP maintained; and 
documented for ILI calibrations prior to the ILI tool run. ILI tool 
calibrations must use ILI tool run results and anomaly calibrations 
from either the Class 1 to Class 3 location segment or from the 
complete ILI tool run in the in-line inspection area. A minimum of four 
calibration excavations should be used for unity plots.
    Regarding the additional repair criteria, subpart O allows metal 
loss anomalies to grow until the predicted failure pressure is 1.1 
times MAOP (i.e., a 10 percent safety factor). PHMSA believes the more 
stringent repair criteria proposed in this NPRM is needed to compensate 
for the lack of newly replaced pipe in locations changing from a Class 
1 to a Class 3. The existing pipe in these locations could include 
pipelines that were built before design and construction standards were 
promulgated in 49 CFR part 192. Such existing pipe may not have the 
steel toughness to mitigate ruptures when the pipe is corroded, dented, 
or has any cracking in the pipe body or pipe seam.
    As such, PHMSA is proposing additional anomaly inspection and 
repair criteria as follows:
     Operators must use high-resolution ILI methods for 
performing integrity assessments.
     Integrity assessments for pipeline segments where the 
class location has changed from Class 1 to Class 3 must also include 
all pipe upstream and downstream of the segment between the nearest 
upstream ILI launcher and the nearest downstream ILI receiver. This 
segment would be defined as the ``in-line inspection segment.''
     Operators would conduct non-destructive SCC inspections 
any time pipe in the in-line inspection segment is exposed (except for 
times a pipe segment is exposed by a third party through a ``one-call'' 
excavation under Sec.  192.614) and where the operator finds disbonded 
or repaired coating (except for pipe that is coated with fusion-bonded 
or liquid-applied epoxy coatings).
    For ILI anomalies identified in the in-line inspection segment, 
PHMSA proposes the following repair criteria that is consistent with 
granted special permit conditions: Immediate repair conditions for pipe 
threats such as metal loss, denting, cracking, and other anomalies that 
are at or near the point of failure. These include metal loss with a 
predicted failure pressure less than or equal to 1.1 times the MAOP, 
crack-type defects with a predicted failure pressure less than 1.25 
times the MAOP, and additional specified criteria dependent on anomaly 
type and size.
    To ensure anomalies in the in-line inspection segment are repaired 
in a timely manner, PHMSA is proposing for operators to repair 
scheduled anomalies in 1 year regardless of whether the applicable 
pipeline segment is in an HCA. One-year scheduled conditions are for 
pipe threats such as metal loss, denting, cracking, and other anomalies 
that are not an immediate threat to integrity but that operators would 
need to repair promptly. PHMSA is also proposing to incorporate a 
tiered approach for the predicted failure pressure criteria for metal 
loss and crack anomalies based on the class location at the anomaly to 
make the criteria more stringent as the class location increases. In 
addition to repair criteria based on predicted failure pressure, PHMSA 
is basing the proposed dent repair criteria on anomaly size and 
location. For Class 1 to Class 3 location segments, PHMSA has also 
established monitored conditions for pipe threats such as metal loss 
denting, cracking, and other anomalies that are not severe enough to

[[Page 65170]]

need prompt repair but that the operator must monitor.
    PHMSA is also proposing additional repair criteria for anomalies 
identified in the Class 1 to Class 3 location segment beyond the 
criteria proposed for the in-line inspection segment. These criteria 
include more conservative criteria for crack anomalies and a 
requirement for operators to repair discovered pipe wall thickness loss 
greater than 40 percent within 1 year. These criteria are based on 
PHMSA research and development projects and were developed in 
conjunction with the repair criteria that the GPAC discussed and voted 
to adopt in 2019.
    In addition, PHMSA is proposing the following maintenance surveys 
to address threats not assessed by ILI and the findings remediated, as 
well as other P&M actions:
     CIS,
     CP test site survey,
     Line-of-sight markers,
     Interference survey,
     Depth-of-cover survey,
     Right-of-way patrols,
     Leakage survey, and
     Shorted casings survey.
    PHMSA also proposes requiring operators install remote-control or 
automatic shutoff valves, or otherwise equip existing valves with 
remote-control or automatic shutoff capability for the mainline block 
valves both upstream and downstream of the class location upgrade 
segment. In this proposed rule, PHMSA is defining the timing for 
remote-control and automatic shutoff valve closure should there be a 
pipeline rupture and is requiring operators use a SCADA system if 
managing class location changes through IM. More specifically, PHMSA is 
proposing a 30-minute valve closure standard to be consistent with 
conditions it has required operators to meet in certain class location 
change special permits. This 30-minute standard would help protect 
populations where Class 1 pipe is not being upgraded and will remain in 
the ground. If operators determine they would not be able to meet this 
30-minute valve closure standard as a part of the IM alternative in 
this NPRM, an operator could apply to PHMSA for a special permit for 
managing their class location change.
    PHMSA is also requiring documentation for pipe properties, pressure 
tests, ILI assessments, surveys, and any other required action 
operators take to comply with this proposed rulemaking.
    Finally, if an operator intends to use the IM alternative to manage 
a pipeline segment that has changed from a Class 1 to a Class 3 
location, the operator must submit a notification to PHMSA within 60 
days of the class location change, in accordance with Sec.  
191.22(c)(2). Such a notification must include details of each pipeline 
segment that experienced a class location change that the operator will 
manage using IM.
    PHMSA requests comments on whether it should consider modifying or 
eliminating any of the O&M procedural requirements of this section, 
including:
    (a) Program requirements, including the eligibility conditions, for 
a Class 1 to Class 3 location segment.
    (b) Pipeline integrity assessments.
    (c) Remediation schedule (In-line inspection segment).
    (d) Special requirements for crack anomalies.
    (e) Pipe and weld cracking inspections.
    (f) Additional preventive and mitigative measures.
    (g) Remote-control or automatic shutoff valves.
    (h) Documentation.
    (i) Notifications to PHMSA of integrity assessment program for 
class 1 to class 3 location segment changes.
    If a commenter determines that any of the above requirements should 
be modified or eliminated, please explain how such a modification or 
elimination would maintain, increase, or decrease the current level of 
pipeline safety and environmental protection. Based on comments 
received, PHMSA may consider modifying or eliminating the above 
requirements if they are not necessary for maintaining pipeline safety 
or protecting the environment and another approach would maximize net 
benefits to society.

Sec.  192.712 Analysis of Predicted Failure Pressure and Critical 
Strain Levels

    In the ``Safety of Gas Transmission Pipelines: MAOP Reconfirmation, 
Expansion of Assessment Requirements, and Other Related Amendments'' 
final rule published on October 1, 2019, PHMSA updated and codified 
minimum standards for determining the predicted failure pressure of 
pipelines containing anomalies or defects associated with corrosion 
metal loss and cracks. In this NPRM, PHMSA is proposing repair criteria 
for the in-line inspection segment and the Class 1 to Class 3 location 
segment, which include repair criteria for dents. Some of the proposed 
dent repair criteria allows operators to determine critical strain 
levels for dents and defer repairs if critical strain levels are not 
exceeded. In this section, PHMSA has established minimum standards for 
calculating critical strain levels in pipe with dent anomalies or 
defects and has included those standards in a new paragraph (c). These 
standards are based off of the dent ECA method discussed and voted on 
as part of the repair criteria discussion at the Gas Pipeline Advisory 
Committee meetings during March 26-28, 2018. The title of this section 
has also been updated to reflect this addition.

Sec.  192.903 What definitions apply to this subpart?

    Section 192.903 provides definitions for various terms used 
throughout part 192 subpart O. In support of the regulations proposed 
in this NPRM, PHMSA is proposing to amend the definition of ``high 
consequence area.'' The revised definition would require operators to 
incorporate any Class 1 to Class 3 location segment, as defined in 
proposed Sec.  192.3, into their IM programs as an HCA.

V. Regulatory Analysis and Notices

A. Statutory/Legal Authority for This Rulemaking

    This proposed rule is published under the authority of the Federal 
Pipeline Safety Law (49 U.S.C. 60101 et seq.). Section 60102 authorizes 
the Secretary of Transportation to issue regulations governing the 
design, installation, inspection, emergency plans and procedures, 
testing, construction, extension, operation, replacement, and 
maintenance of pipeline facilities. Further, section 60102(l) requires 
the Secretary, to the extent appropriate and practicable, to update 
incorporated industry standards that have been adopted as a part of the 
pipeline safety regulations. The Secretary has delegated the authority 
vested in the Secretary by the Pipeline Safety Law to the PHMSA 
Administrator under 49 CFR 1.97.

B. Executive Order 12866 and DOT Regulatory Policies and Procedures

    Executive Order 12866, Regulatory Planning and Review, (58 FR 
51735; Oct. 4, 1993), 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.'' The Executive 
Order and DOT regulations governing rulemaking procedures (49 CFR part 
5) require that PHMSA submit ``significant regulatory actions'' to OMB 
for review. The proposed rulemaking is a ``significant regulatory 
action'' under section 3(f) of Executive Order 12866 and DOT rulemaking 
regulations. The proposed rulemaking has been reviewed by the Office of 
Management and

[[Page 65171]]

Budget in accordance with Executive Order 12866 and is consistent with 
the Executive Order 12866 requirements and 49 U.S.C. 60102(b)(5)-(6).
    The tables below summarize the annualized cost savings for the 
provisions in the proposed rule. PHMSA anticipates that, if 
promulgated, the proposals in this NPRM would have economic benefits to 
the public and the regulated community by reducing cost burdens without 
increasing risks to public safety or the environment. These estimates 
reflect the assumption that the IM alternative for managing class 
location changes proposed in this rule will be a less-costly 
alternative to the current regulatory requirements.
    PHMSA estimates that the proposed rule will result in annualized 
cost savings of approximately $55 to $86 million per year, based on its 
analysis of two different scenarios and at a 7 percent discount 
rate.\108\ The tables below present the annualized costs for the 
baseline and this proposed rule, for both scenarios examined, at a 3 
percent and a 7 percent discount rate:
---------------------------------------------------------------------------

    \108\ Scenario 1 averaged PHMSA's estimates, annually and from a 
low- and high-end concept, of the number of miles that would change 
from a Class 1 to a Class 3 location and where operators would use 
the IM alternative. This estimate was 77.6 miles per year. Scenario 
2 took the median of PHMSA's estimates, annually and from a low- and 
high-end concept, and this estimate was 117.6 miles per year. See 
Section 3 of the Preliminary Regulatory Impact Analysis for more 
details.

            Annualized Proposed Rule Cost Savings, Scenario 1
                          [2020-2039, millions]
------------------------------------------------------------------------
                                                   Discount rate
                                         -------------------------------
                                                3%              7%
------------------------------------------------------------------------
                               Baseline *
------------------------------------------------------------------------
Pipe Replacement........................          $206.7          $206.7
Special Permits.........................             9.0             8.0
                                         -------------------------------
    Total Cost..........................           215.7           214.7
------------------------------------------------------------------------
                              Proposed Rule
------------------------------------------------------------------------
Pipe Replacement........................           135.8           135.8
Special Permits.........................             2.5             2.2
New Compliance Method...................            23.8            21.8
                                         -------------------------------
    Total Cost..........................           162.1           159.8
                                         -------------------------------
        Net Annualized Cost.............           -53.6           -54.9
------------------------------------------------------------------------
* Operators also have the option to use a pressure test or pressure
  reduction to manage the class location change. To the extent operators
  find the new class location MAOP acceptable, the decision by operators
  to use these options is not affected by the addition of the proposed
  rule compliance method. Therefore, the rule has no incremental effect
  on these compliance options.

            Annualized Proposed Rule Cost Savings, Scenario 2
                          [2020-2039, millions]
------------------------------------------------------------------------
                                                   Discount rate
                                         -------------------------------
                                                3%              7%
------------------------------------------------------------------------
                               Baseline *
------------------------------------------------------------------------
Pipe Replacement........................          $326.7          $326.7
Special Permits.........................             9.0             8.0
                                         -------------------------------
    Total Cost..........................           335.7           334.7
------------------------------------------------------------------------
                              Proposed Rule
------------------------------------------------------------------------
Pipe Replacement........................           214.6           214.6
Special Permits.........................             2.5             2.2
New Compliance Method...................            34.8            31.8
                                         -------------------------------
    Total Cost..........................           251.9           248.7
                                         -------------------------------
        Net Annualized Cost.............           -83.8             -86
------------------------------------------------------------------------
* Operators also have the option to use a pressure test or pressure
  reduction to manage the class location change. To the extent operators
  find the new class location MAOP acceptable, the decision by operators
  to use these options is not affected by the addition of the proposed
  rule compliance method. Therefore, the rule has no incremental effect
  on these compliance options.

[[Page 65172]]

    For more information, please see the PRIA in the docket for this 
rulemaking.

C. Executive Order 13771

    This proposed rule is expected to be a deregulatory action under 
Executive Order 13771. Details on the estimated costs of this proposed 
rule can be found in the PRIA in the rulemaking docket.

D. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) (5 U.S.C. 601 et seq.) 
requires federal agencies to review each rulemaking action to consider 
whether it would have a ``significant economic impact on a substantial 
number of small entities'' to include small businesses, not-for-profit 
organizations that are independently owned and operated and are not 
dominant in their fields, and governmental jurisdictions with 
populations under 50,000. This NPRM was developed in accordance with 
Executive Order 13272, ``Proper Consideration of Small Entities in 
Agency Rulemaking'' (68 FR 7990, Feb. 19, 2003) and DOT's procedures 
and policies to promote compliance with the RFA and to ensure that the 
potential impacts of a regulatory action on small entities were 
properly considered.
    Based on the analysis within the PRIA in the rulemaking document, 
which PHMSA has summarized below, PHMSA expects that this rulemaking 
will not have a significant economic impact on a substantial number of 
small entities. However, PHMSA seeks public comment on its analysis.
(1) Statement of the Need for, and Objectives of, the Rulemaking
    In this rulemaking PHMSA proposes to add an alternative set of 
requirements within the PSR that operators could use, based on 
implementing integrity management principles and pipe eligibility 
criteria, to manage certain pipeline segments where the class location 
has changed from a Class 1 location to a Class 3 location. Through 
required periodic assessments, repair criteria, and other extra 
preventive and mitigative measures, PHMSA expects this alternative 
approach would providing cost savings for pipeline operators without 
adversely affecting safety. The need for and objectives of this 
rulemaking are discussed further above in Section I.A (``Purpose of 
Regulatory Action'').
(2) Description of the Small Entities That Could Be Affected by the 
Rulemaking and Their Estimated Compliance Costs
    The RFA obliges PHMSA to assess whether the rulemaking would have 
``a significant impact on a substantial number of small entities. This 
assessment involves (1) identifying the domestic parent entities for 
affected operators, (2) determining which are small entities based on 
Small Business Administration size criteria, and (3) assessing the 
potential impact of the rule on those small entities based on estimated 
entity-level annualized compliance cost savings and annual revenues. 
Although PHMSA's analysis on each of these issues is provided in 
greater detail within the PRIA in the rulemaking docket, that analysis 
is summarized below.
    There are currently 1,099 operators of onshore natural gas 
transmission pipelines, and approximately 85 percent, or 939 operators 
operate Class 1 pipelines. PHMSA estimates that operators of Class 1 
pipelines are owned by 324 parent entities, and of these, 254 are small 
entities. Small entities operate approximately 5,200 miles of Class 1 
pipeline, which is only about 2.2 percent of all Class 1 pipeline.
    The NPRM does not eliminate any of the currently available options 
for management of changes from Class 1 to Class 3, but would rather 
provide flexibility to operators by enabling the use of another 
compliance option. Since PHMSA expects that the approach introduced in 
this NPRM would cost less than the other predominately used options--
pipeline replacement and special permit--such that small entities would 
have the opportunity to achieve cost savings should they need to manage 
class location changes in the future for pipeline segments that meet 
the eligibility criteria set forth in this NPRM.
    The quantity, character, and location of future class changes is 
highly uncertain, particularly on a year-to-year basis. In any given 
year, only a subset of pipelines will experience a change from Class 1 
to Class 3. PHMSA is not able to develop an annual forecast describing 
specific pipeline segments changing classes or to what extent those 
changes will be managed by small versus large operators. Over the 20-
year period of analysis, PHMSA assumes that each pipeline operator will 
manage a share of the future changes from Class 1 to Class 3 that is 
proportional to the total miles of Class 1 pipeline it operates.
    PHMSA estimates that small entities will manage an aggregate 1.7 to 
2.6 miles of pipeline changing from Class 1 to Class 3 annually, in 
Scenarios 1 and 2, respectively. Aggregate annualized cost savings for 
small entities is estimated to be $1.17-$1.19 million in Scenario 1, 
using 3 and 7 percent discount rates, respectively; annualized small 
entity savings is $1.8-$1.9 million in Scenario 2. Under Scenario 1, 
the average annual cost savings per small entity is $4,700, with a 
median savings of $1,500 per year. Under Scenario 2, the average per-
entity annual savings is $7,400, with a median of $2,300.
    PHMSA estimates only about 1 percent of Class 1 pipeline miles will 
be affected by a change to Class 3 in total over the next 20 years. 
Based on PHMSA's high-end Scenario 2 estimate of 117.6 miles per year, 
only 2,352 miles will make this change over the next 20 years. 
Annually, the proposed rule affects 0.05 percent of Class 1 miles. The 
characteristics of this small subset of affected pipeline miles (or 
segments) will ultimately determine the extent to which large and small 
entities ultimately avail themselves of the proposed rule option. Given 
that small entities operate only about 2 percent of Class 1 miles, 
large entities in the aggregate are more likely to experience a 
pipeline segment requiring a change from Class 1 to Class 3.
    It is also important to note that although the savings are 
presented here on an annualized basis, the vast majority of small 
entities will likely not have to manage a change from Class 1 to Class 
3 for any pipeline miles in a given year. For instance, PHMSA's 
estimate of 1.7 to 2.6 miles per year of Class 1 to Class 3 changes 
managed by small entities (Scenarios 1 and 2), and PHMSA's estimated 
average segment length of 0.26 miles, suggests an average of 7 to 10 
segments per year experiencing a change from Class 1 to Class 3 across 
the entire pipeline industry. If each operator only manages one segment 
changing from Class 1 to Class 3 each year, then only 7 to 10 small 
entities (or fewer if operators manage multiple segments in one year) 
may manage a Class 1 to Class 3 change per year, out of 254 total 
affected small entities.
(3) Significant Alternatives Considered
    PHMSA does not expect this proposed rulemaking to have a 
significant economic impact on small businesses. Further, the changes 
to the PSR proposed in this NPRM are generally intended to provide 
regulatory flexibility and cost savings to industry members without 
adversely affecting safety. PHMSA solicits public comment on the 
economic impact on small entities, and potential alternatives that 
reduce any economic impact on small entities.

[[Page 65173]]

(4) Duplicative, Overlapping, and Conflicting Federal Rules
    PHMSA is unaware of any Federal regulations that are substantially 
similar to the proposals in this NPRM and which would duplicate, 
overlap, or conflict with the PSR revisions proposed.

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

    PHMSA analyzed this proposed rule per the principles and criteria 
in Executive Order 13175, ``Consultation and Coordination with Indian 
Tribal Governments'' (65 FR 67249; Nov. 6, 2000) and under DOT Order 
5301.1. Because PHMSA does not anticipate that this proposed rule will 
have tribal implications, the funding and consultation requirements of 
Executive Order 13175 would not apply. PHMSA seeks comment on the 
applicability of the Executive Order to this proposed rule.

F. Paperwork Reduction Act

    The Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.) 
establishes policies and procedures for controlling paperwork burdens 
imposed by Federal agencies on the public. Pursuant to 44 U.S.C. 
3506(c)(2)(B) and 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. The proposals in this NPRM will trigger new notification 
requirements for pipeline operators who experience a change in their 
class location.
    PHMSA proposes to create a new information collection to help 
operators comply with the proposed revision to the PSR. Operators will 
be required to notify PHMSA if they choose to use an alternative to an 
inline-inspection device when conducting pressure tests on their 
pipelines. Operators will also be required to notify PHMSA if they use 
integrity management protocols to manage pipeline segments that have 
changed from a Class 1 to a Class 3 location. PHMSA will request a new 
Control Number from OMB for this new information collection.
    PHMSA will submit an information collection request to OMB for 
approval based on the proposed requirements in this NPRM. The 
information collection is contained in the PSR, 49 CFR parts 190-199. 
The following information is provided for this 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 is 
estimated as follows:
    1. Title: Class Location Change Notification Requirements.
    OMB Control Number: Will request from OMB.
    Current Expiration Date: TBD.
    Abstract: This information collection covers the collection of data 
from owners and operators of pipelines. Pipeline operators are required 
to notify PHMSA in the event of certain instances that pertain to a 
change in their class location.
    Affected Public: Owners and operators of pipelines.
    Annual Reporting Burden:
    Total Annual Responses: 100.
    Total Annual Burden Hours: 25.
    Frequency of Collection: On occasion.
    Requests for a copy of this information collection 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 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 December 14, 2020. Comments 
may also be sent via email to the Office of Management and Budget at 
the following address: oira_submissions@omb.eop.gov.

G. Unfunded Mandates Reform Act of 1995

    The Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1501 et seq.) 
requires Federal agencies to prepare and consider estimates of the 
budgetary impact of regulations containing Federal mandates upon State, 
local, and Tribal governments before adopting such regulations. This 
NPRM imposes no unfunded mandates. If promulgated, this rule would not 
result in costs of $100 million, adjusted for inflation, or more in any 
one year to either State, local, or Tribal governments, in the 
aggregate, or to the private sector. A copy of the PRIA is available 
for review in the docket.

H. National Environmental Policy Act

    The National Environmental Policy Act (NEPA) (42 U.S.C. 4321 et. 
seq.) requires Federal agencies to prepare a detailed statement on 
major Federal actions significantly affecting the quality of the human 
environment. PHMSA analyzed this NPRM in accordance with NEPA, Council 
on Environmental Quality regulations (40 CFR parts 1500-1508), and DOT 
Order 5610.1C. PHMSA has prepared a draft Environmental Assessment (EA) 
and has preliminarily determined this action will not significantly 
affect the quality of the human environment. A copy of the EA for this 
action is available in the docket. PHMSA invites comment on the 
environmental impacts of this proposed rulemaking.

I. Executive Order 13132: Federalism

    Executive Order 13132, ``Federalism'' (64 FR 43255; Aug. 10, 1999) 
imposes certain requirements on Federal agencies formulating or 
implementing policies or regulations that preempt State law or that 
have federalism implications. This NPRM does not impose 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 NPRM also 
does not impose substantial direct compliance costs on State and local 
governments.
    The proposed rule could have preemptive effect because the pipeline 
safety laws, specifically 49 U.S.C. 60104(c), prohibit State safety 
regulation of interstate pipelines. Under the pipeline safety law, 
States can augment pipeline safety requirements for intrastate 
pipelines but may not approve safety requirements less stringent than 
those required by Federal law. A State may also regulate an intrastate 
pipeline

[[Page 65174]]

facility not otherwise covered by PHMSA regulations. In this instance, 
the preemptive effect of the proposed rule is limited to the minimum 
level necessary to achieve the objectives of the pipeline safety laws 
under which the proposed rule is promulgated. Therefore, the 
consultation and funding requirements of E.O. 13132 do not apply.

J. Executive Order 13211

    This proposed rule is not a ``significant energy action'' under 
Executive Order 13211, ``Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use'' (66 FR 
28355; May 22, 2001). 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 proposed 
rule as a significant energy action.

K. 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), at http://www.dot.gov/privacy.

L. 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 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

    Class location change reporting, pipeline reporting requirements.

49 CFR Part 192

    Class location change, integrity management, pipeline safety.

    In consideration of the foregoing, PHMSA is proposing to revise 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 continues 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. Amend Sec.  191.22 by adding paragraph (c)(2)(vi) to read as 
follows:

Sec.  191.22  National Registry of Operators.

* * * * *
    (c) * * *
    (2) * * *
    (vi) A change in the classification of a pipeline segment from a 
Class 1 to a Class 3 location where the operator chooses to confirm or 
revise the maximum allowable operating pressure (MAOP) in accordance 
with Sec.  192.611(a)(4) of this chapter. The notification must include 
the following information about the Class 1 to Class 3 location 
segment: State, county, pipeline name or number, pipe diameter, MAOP, 
wall thickness, pipe grade/strength, seam type, Class 1 to Class 3 
location change date, segment length, pipeline location by both GIS 
coordinates and pipeline system survey stations or mile posts for the 
starting and ending points of the Class 1 to Class 3 location segment, 
and the date of the Class 1 to Class 3 location change.
* * * * *

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

0
3. The authority citation for part 192 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
4. Amend Sec.  192.3 by adding the definitions of ``Class 1 to Class 3 
location segment'', ``In-line inspection segment'', and ``Predicted 
failure pressure'' in alphabetical order to read as follows:

Sec.  192.3  Definitions.

* * * * *
    Class 1 to Class 3 location segment means a pipeline segment where:
    (1) The segment has changed from a Class 1 to a Class 3 location; 
and
    (2) The operator is confirming or revising the maximum allowable 
operating pressure per Sec.  192.611(a)(4). At the operator's 
discretion, the endpoints of the Class 1 to Class 3 location segment 
may extend further than the beginning and endpoints of the Class 3 
location involved.
* * * * *
    In-line inspection segment means all pipe within a Class 1 to Class 
3 location segment and all pipe adjacent to the Class 1 to Class 3 
location segment between the nearest upstream in-line inspection 
launcher and the nearest downstream in-line inspection receiver.
* * * * *
    Predicted failure pressure means the calculated pipeline anomaly 
failure pressure, based on the use of an appropriate engineering 
evaluation method for the type of anomaly being assessed, that does not 
have an included safety factor. Different anomaly types (e.g., dent, 
crack, or metal loss) will require different engineering assessment or 
analysis methods to determine the predicted failure pressure.
* * * * *
0
5. Amend Sec.  192.7 by revising paragraphs (b)(12) and (c)(6) to read 
as follows:

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

* * * * *
    (b) * * *
    (12) API STANDARD 1163, ``In-Line Inspection Systems 
Qualification,'' Second edition, April 2013, Reaffirmed August 2018, 
(API STD 1163), IBR approved for Sec. Sec.  192.493, 192.618(b)(4), and 
(b)(4)(iii).
* * * * *
    (c) * * *
    (6) ASME/ANSI B31.8S-2004, ``Supplement to B31.8 on Managing System 
Integrity of Gas Pipelines,'' 2004, (ASME/ANSI B31.8S-2004), IBR 
approved for Sec. Sec.  192.618; 192.903 note to Potential impact 
radius; 192.907 introductory text, (b); 192.911 introductory text, (i), 
(k), (l), (m); 192.913(a), (b), (c); 192.917 (a), (b), (c), (d), (e); 
192.921(a); 192.923(b); 192.925(b); 192.927(b), (c); 192.929(b); 
192.933(c), (d); 192.935 (a), (b); 192.937(c); 192.939(a); and 
192.945(a).
0
6. Amend Sec.  192.611 by adding paragraph (a)(4) and revising 
paragraph (d) to read as follows:

Sec.  192.611  Change in class location: Confirmation or revision of 
maximum allowable operating pressure.

    (a) * * *
    (4) A Class 1 to Class 3 location segment may have its maximum 
allowable operating pressure confirmed or revised in accordance with 
Sec.  192.618.
* * * * *
    (d) Confirmation or revision of the maximum allowable operating 
pressure that is required as a result of a study under Sec.  192.609 
must be completed within 24 months of the change in class location. 
Pressure reduction under paragraph (a)(1) or (2) of this section within 
the 24-month period does not preclude establishing a maximum allowable 
operating pressure under paragraph (a)(3) of this section or 
implementing an integrity assessment program that meets paragraph 
(a)(4) of this section at a later date. The activities required in 
paragraphs (a)(3) or (4) of this section must be implemented prior to 
any future increases of maximum

[[Page 65175]]

allowable operating pressure to meet paragraphs (a)(1) or (2) of this 
section.
0
7. Add Sec.  192.618 to read as follows:

Sec.  192.618  Class 1 to Class 3 location segment requirements.

    A Class 1 to Class 3 location segment must meet the following 
requirements:
    (a) Program requirements for a Class 1 to Class 3 location segment. 
For segments that change from a Class 1 to a Class 3 location, the 
maximum allowable operating pressure (MAOP) must be confirmed or 
revised by designating the segment involved as a high consequence area, 
as defined in Sec.  192.903, and including it in an integrity 
management program in accordance with subpart O of this part, if the 
following criteria are met:
    (1) Timing of Class 1 to Class 3 location change. The Class 1 to 
Class 3 location segment change must have occurred after [INSERT 
EFFECTIVE DATE OF FINAL RULE]. An operator must conduct a class 
location study on the in-line inspection segment at least once each 
calendar year, with intervals not to exceed 15 months, in accordance 
with Sec.  192.609. An operator must maintain its in-line inspection 
segment change in class location study records in accordance with 
paragraph (h) of this section.
    (2) In-line inspection. The in-line inspection segment must be 
assessed using instrumented in-line inspection tools that meet the 
requirements of paragraph (b)(1) of this section.
    (3) Hoop stress of Class 1 to Class 3 location segment. The hoop 
stress corresponding to the MAOP of the Class 1 to Class 3 location 
segment must not exceed 72 percent of SMYS in Class 3 locations.
    (4) Pipe attributes for review. Pipeline segments with any of the 
following attributes cannot be a Class 1 to Class 3 location segment:
    (i) Bare pipe;
    (ii) Pipe with wrinkle bends;
    (iii) Pipe that does not have traceable, verifiable, and complete 
pipe material records for diameter, wall thickness, grade, seam type, 
yield strength, and tensile strength;
    (iv) Pipe that is uprated in accordance with subpart K (unless the 
segment passes a subpart J pressure test for a minimum of 8 hours at a 
minimum pressure of 1.39 times MAOP within 24 months after the Class 1 
to Class 3 location segment change and prior to uprating or increasing 
the current MAOP);
    (v) Pipe that has not been pressure tested in accordance with 
subpart J for 8 hours at a minimum test pressure of 1.25 times MAOP 
(unless the segment passes a subpart J pressure test for a minimum of 8 
hours at a minimum pressure of 1.25 times MAOP within 24 months after 
the Class 1 to Class 3 location segment change);
    (vi) Pipe with direct current (DC), low frequency electric 
resistance welded (LF-ERW), electric flash welded (EFW), or lap-welded 
seams, or pipe with a longitudinal joint factor below 1.0; or
    (vii) Pipe with cracking in the pipe body, seam, or girth welds in 
or within 5 miles of the Class 1 to Class 3 location segment that is 
over 20 percent of the pipe wall thickness, has a predicted failure 
pressure less than 100 percent of SMYS, has a predicted failure 
pressure less than 1.50 times MAOP, has experienced a leak or a rupture 
due to pipe cracking, or for which analysis in accordance with 
paragraph (e) of this section indicates the pipe could fail in brittle 
mode.
    (viii) Poor pipe external coating that requires a minimum negative 
cathodic polarization voltage shift of 100 millivolts or linear anodes 
along the Class 1 to Class 3 location segment to maintain cathodic 
protection in accordance with Sec.  192.463, or a Class 1 to Class 3 
location segment with tape wraps or shrink sleeves.
    (ix) Pipe that transports gas whose composition quality is not 
suitable for sale to gas distribution customers, including, but not 
limited to, pipe with free-flowing water or hydrocarbons, water vapor 
content exceeding acceptable limits for gas distribution customer 
delivery, hydrogen sulfide (H2S) greater than one grain per 
100 cubic feet, or carbon dioxide (CO2) greater than 3 
percent by volume.
    (x) Pipelines operating in accordance with Sec.  192.619(c) or (d).
    (xi) A Class 1 to Class 3 location segment, in-line inspection 
segment, or portion of it that has been previously denied by the 
special permit process in Sec.  190.341.
    (b) Pipeline integrity assessments. In addition to the requirements 
specified in subpart O of this part, pipeline integrity assessments for 
the in-line inspection segment, including the Class 1 to Class 3 
location segment, must meet the following:
    (1) Assessment method. Operators must perform pipeline assessments 
using the following in-line inspection tools or alternative methods as 
applicable for the pipeline integrity threats being assessed:
    (i) In-line inspection with a high-resolution magnetic flux leakage 
(HR-MFL) tool or an equivalent internal inspection device;
    (ii) In-line inspection with a high-resolution deformation tool 
(HR-Deformation), with sensors and extension arms outside the tool 
cups, or an equivalent internal inspection device;
    (iii) In-line inspection with an electromagnetic acoustic 
transducer (EMAT) tool or an equivalent internal inspection device;
    (iv) In-line inspection with an inertial measurement unit (IMU) 
tool or an equivalent internal inspection device;
    (v) An operator may use alternative methods, such as pressure 
testing or other technology (excluding direct assessment), upon 
submitting a notification to PHMSA 90 days prior to using the 
alternative method, in accordance with Sec.  192.18.
    (vi) If an operator chooses not to conduct the in-line inspection 
as required in paragraphs (iii) or (iv) on a pipeline segment with a 
history of pipe body or weld cracking or pipe movement, then the 
operator must notify PHMSA in accordance with Sec.  192.18.
    (2) Initial assessment. Within 24 months of the Class 1 to Class 3 
location segment change, an operator must identify and document each 
integrity threat to which the pipeline segment is susceptible and 
conduct initial pipeline integrity assessments of the entire in-line 
inspection segment for each threat in accordance with Sec. Sec.  
192.917, 192.921, and paragraph (b)(1) of this section.
    (3) Reassessments. The operator must conduct periodic reassessments 
in accordance with Sec.  192.937 and paragraph (b)(1) of this section 
at least once every 7 calendar years, with intervals not to exceed 90 
months, as specified in Sec.  192.939(a).
    (4) In-line Inspection Validation. Operators must validate the 
results of all in-line inspections, for each type in-line inspection 
tool run conducted in accordance with this section, to Level 3 
standards in accordance with API Standard 1163 (incorporated by 
reference, see Sec.  192.7).
    (i) 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 performance) when identifying 
and characterizing anomalies.
    (ii) For each threat type assessed by ILI tool type, an operator 
must validate the in-line inspection tool tolerance for each in-line 
inspection tool run using a minimum of 4 anomaly validations or 100 
percent of anomalies, whichever is

[[Page 65176]]

less, either from new excavations or from past excavations in the in-
line inspection segment, with documented anomaly dimensions (width, 
depth, length, and location) or other known pipe features that are 
appropriate for the in-line inspection tool.
    (iii) For pipeline areas of metal loss where in-line inspection 
tool data for anomaly size and characterization are used in the 
determination of the predicted anomaly failure pressure, an operator 
must use Section 6.2.3, Table 1--Characterizing Metal Loss 
Probabilities of Detection--Depth Detection Threshold, in accordance 
with API Standard 1163 (incorporated by reference, see Sec.  192.7). 
Using the qualifiers and limitation criteria in Section 6.2.3, Table 1 
of API Standard 1163 or technically proven criteria appropriate for the 
location, size, and type of the anomaly, an operator must evaluate the 
anomaly based on whether it is an extended metal loss, pit, or groove.
    (iv) An operator may use alternative methods for in-line inspection 
tool verification, such as calibration joints near the upstream and 
downstream ILI tool launchers and receivers, upon submitting a 
notification to PHMSA 90 days prior to using the alternative method, in 
accordance with Sec.  192.18.
    (5) 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. A condition that presents a potential threat includes, but is 
not limited to, those conditions that require remediation or monitoring 
listed under Sec.  192.933 and paragraphs (c), (d), and (e) of this 
section. An operator must promptly, but no later than 180 days after 
conducting a pipeline integrity assessment, obtain sufficient 
information about a condition to make such a determination of an 
integrity threat that requires remediation.
    (c) Remediation schedule (In-line inspection segment). In addition 
to the requirements specified in subpart O of this part, remediation 
for the in-line inspection segment, including the Class 1 to Class 3 
location segment, must meet the following:
    (1) Immediate repair conditions. An operator must repair the 
following conditions immediately upon discovery:
    (i) Metal loss anomalies where the calculation of the remaining 
strength of the pipe shows a predicted failure pressure determined in 
accordance with Sec.  192.712(b) less than or equal to 1.1 times the 
MAOP at the location of the anomaly.
    (ii) Metal loss greater than 80 percent of nominal wall, regardless 
of dimensions.
    (iii) Metal loss preferentially affecting a detected longitudinal 
seam and where the predicted failure pressure determined in accordance 
with Sec.  192.712(d) is less than or equal to 1.25 times the MAOP.
    (iv) A dent located between the 8 o'clock and 4 o'clock positions 
(upper \2/3\ of the pipe) that has metal loss, cracking, or a stress 
riser, unless a technically proven engineering analysis conducted in 
accordance with Sec.  192.712(c) demonstrates that critical strain 
levels will not be exceeded before the next engineering analysis or 
assessment is conducted.
    (v) A crack or crack-like anomaly meeting any of the following 
criteria:
    (A) Crack depth plus any metal loss is greater than 50 percent of 
pipe wall thickness;
    (B) Crack depth plus any metal loss is greater than the inspection 
tool's maximum measurable depth; or
    (C) The crack or crack-like anomaly has a predicted failure 
pressure, determined in accordance with Sec.  192.712(d), that is less 
than 1.25 times the MAOP.
    (vi) An indication or anomaly that, in the judgment of the person 
designated by the operator to evaluate the assessment results, requires 
immediate action.
    (2) One-year conditions. An operator must repair the following 
conditions within 1 year of discovery:
    (i) A smooth dent located between the 8 o'clock and 4 o'clock 
positions (upper \2/3\ of the pipe) with a depth greater than 6 percent 
of the pipeline diameter (greater than 0.50 inches in depth for a 
pipeline diameter less than Nominal Pipe Size (NPS) 12), unless an 
engineering analysis conducted in accordance with Sec.  192.712(c) 
demonstrates that critical strain levels will not be exceeded before 
the next engineering analysis or assessment is conducted.
    (ii) A dent with a depth greater than 2 percent of the pipeline 
diameter (0.250 inches in depth for a pipeline diameter less than NPS 
12) that affects pipe curvature at a girth weld or at a longitudinal or 
helical (spiral) seam weld, unless an engineering analysis conducted in 
accordance with Sec.  192.712(c) demonstrates that critical strain 
levels will not be exceeded before the next engineering analysis or 
assessment is conducted.
    (iii) A dent located between the 4 o'clock and 8 o'clock positions 
(lower \1/3\ of the pipe) that has metal loss, cracking, or a stress 
riser, unless an engineering analysis conducted in accordance with 
Sec.  192.712(c) demonstrates that critical strain levels will not be 
exceeded before the next engineering analysis or assessment is 
conducted.
    (iv) Metal loss anomalies where a calculation of the remaining 
strength of the pipe shows a predicted failure pressure, determined in 
accordance with Sec.  192.712(b), at the location of the anomaly less 
than or equal to 1.39 times the MAOP for Class 2 locations, and 1.50 
times the MAOP for Class 3 and 4 locations. For metal loss anomalies in 
Class 1 locations outside the Class 1 to Class 3 location segment with 
a predicted failure pressure greater than 1.1 times MAOP, an operator 
must follow the remediation schedule specified in ASME/ANSI B31.8S 
(incorporated by reference, see Sec.  192.7), section 7, figure 4. For 
Class 1 pipe within the Class 1 to Class 3 location segment, a metal 
loss anomaly with a predicted failure pressure of less than or equal to 
1.39 times the MAOP.
    (v) Metal loss that is located at a crossing of another pipeline, 
is in an area with widespread circumferential corrosion, or could 
affect a girth weld, with a predicted failure pressure determined in 
accordance with Sec.  192.712(b) less than 1.39 times the MAOP for 
Class 1 locations or where Class 2 locations contain Class 1 pipe, or 
1.50 times the MAOP for all other Class 2 locations and all Class 3 and 
Class 4 locations. For Class 1 pipe within the Class 1 to Class 3 
location segment, metal loss with a predicted failure pressure of less 
than or equal to 1.39 times the MAOP.
    (vi) Metal loss preferentially affecting a detected longitudinal 
seam and where the predicted failure pressure determined in accordance 
with Sec.  192.712(d) is less than 1.39 times the MAOP for Class 1 
locations or where Class 2 locations contain Class 1 pipe, or 1.50 
times the MAOP for all other Class 2 locations and all Class 3 and 
Class 4 locations. For Class 1 pipe within the Class 1 to Class 3 
location segment, metal loss with a predicted failure pressure of less 
than or equal to 1.39 times the MAOP.
    (vii) A crack or crack-like anomaly that has a predicted failure 
pressure determined in accordance with Sec.  192.712(d) that is less 
than or equal to 1.39 times the MAOP for Class 1 locations or where 
Class 2 locations contain Class 1 pipe, or 1.50 times the MAOP for all 
other Class 2 locations and all Class 3 and Class 4 locations. For 
Class 1 pipe within the Class 1 to Class 3 location segment, a crack or 
crack-like anomaly with a predicted

[[Page 65177]]

failure pressure of less than or equal to 1.39 times the MAOP.
    (3) Remediation schedule (Class 1 to Class 3 location segment). In 
addition to the requirements in paragraph (e) of this section, 
remediation for the Class 1 to Class 3 location segment must meet the 
following:
    (i) One-year condition. An operator must repair the following 
conditions within 1 year of discovery:
    (A) Pipe wall thickness loss greater than 40 percent.
    (B) A crack with depth greater than 40 percent of the pipe wall 
thickness.
    (ii) [Reserved].
    (4) Two-year condition for crack repairs (in-line inspection 
segment). An operator must repair the following condition within 2 
years of discovery:
    (i) A crack or crack-like anomaly that has a predicted failure 
pressure determined in accordance with Sec.  192.712(d) that is greater 
than or equal to 1.39 times MAOP, and the crack depth is greater than 
or equal to 40 percent of the pipe wall thickness.
    (ii) [Reserved].
    (5) Monitored condition. An operator does not have to schedule the 
following conditions for remediation but must record and monitor the 
conditions during subsequent risk assessments and integrity assessments 
for any change that may require remediation. Monitored conditions are 
the least severe and will not require examination and evaluation until 
the next scheduled integrity assessment interval, provided an analysis 
shows they are not expected to grow to dimensions meeting a 1-year 
condition prior to the next scheduled assessment. Monitored conditions 
are:
    (i) A dent with a depth greater than 6 percent of the pipeline 
diameter (greater than 0.50 inches in depth for a pipeline diameter 
less than NPS 12) located between the 4 o'clock position and the 8 
o'clock position (bottom \1/3\ of the pipe);
    (ii) A dent located between the 8 o'clock and 4 o'clock positions 
(upper \2/3\ of the pipe) with a depth greater than 6 percent of the 
pipeline diameter (greater than 0.50 inches in depth for a pipeline 
diameter less than NPS 12), and an engineering analysis conducted in 
accordance with Sec.  192.712(c) demonstrate that critical strain 
levels on the dent will not be exceeded;
    (iii) A dent with a depth greater than 2 percent of the pipeline 
diameter (0.250 inches in depth for a pipeline diameter less than NPS 
12) that affects pipe curvature at a girth weld or longitudinal or 
helical (spiral) seam weld, and an engineering analysis conducted in 
accordance with Sec.  192.712(c) demonstrates that critical strain 
levels on the dent and girth or seam weld will not be exceeded;
    (iv) A dent that has metal loss, cracking, or a stress riser, and 
an engineering analysis conducted in accordance with Sec.  192.712(c) 
demonstrates that critical strain levels will not be exceeded;
    (v) Metal loss preferentially affecting a detected longitudinal 
seam and where the predicted failure pressure determined in accordance 
with Sec.  192.712(d) is greater than 1.39 times the MAOP for Class 1 
locations or where Class 2 locations contain Class 1 pipe, or 1.50 
times the MAOP for all other Class 2 locations and all Class 3 and 
Class 4 locations. For Class 1 pipe within the Class 1 to Class 3 
location segment, metal loss with a predicted failure pressure of less 
than or equal to 1.39 times the MAOP; and
    (vi) A crack or crack-like anomaly for which the predicted failure 
pressure, determined in accordance with Sec.  192.712(d), is greater 
than 1.39 times the MAOP for Class 1 locations or where Class 2 
locations contain Class 1 pipe, or 1.50 times the MAOP for all other 
Class 2 locations and all Class 3 and Class 4 locations. For Class 1 
pipe within the Class 1 to Class 3 location segment, a crack or crack-
like anomaly with a predicted failure pressure greater than 1.39 times 
the MAOP.
    (d) Special requirements for crack anomalies. If cracks are 
discovered in the Class 1 to Class 3 location segment that meet the 
criteria in paragraph (a)(4)(vii) of this section, the operator must 
implement the requirements in Sec.  192.611(a)(1), (2), or (3) within 2 
years. Until the pipe is replaced, operators must remediate cracks as 
specified in paragraph (c) of this section.
    (e) Pipe and weld cracking inspections. Except for pipe coated with 
fusion-bonded or liquid-applied epoxy coatings and excavations 
performed in accordance with Sec.  192.614(c), an operator must inspect 
any pipe in the in-line inspection segment, including the Class 1 to 
Class 3 location segment, that is uncovered for any reason to evaluate 
the pipe for cracking where the coating is removed. An operator must 
use non-destructive examination methods and procedures appropriate for 
the type of non-destructive examination method, and for the type of 
pipe and integrity threat conditions in the ditch. If an operator finds 
any cracking, the operator must conduct an analysis in accordance with 
Sec.  192.712 and remediate anomalies in accordance with paragraphs (c) 
and (d) of this section.
    (f) Additional preventive and mitigative measures. For a Class 1 to 
Class 3 location segment, an operator must conduct the following 
operations and maintenance actions and surveys within 2 years of the 
Class 1 to Class 3 location segment change, evaluate the findings, and 
remediate as follows:
    (1) Close interval surveys with an ``on and off'' current at a 
maximum 5-foot spacing. An operator must evaluate in accordance with 
Sec.  192.463 and remediate the unprotected pipe segments within 1 year 
of the survey. Operators must conduct close interval surveys on 
reassessment intervals of at least once every 7 calendar years, with 
intervals not to exceed 90 months.
    (2) At least 1 cathodic protection pipe-to-soil test station must 
be located within the Class 1 to Class 3 location segment with a 
maximum spacing of \1/2\ mile between test stations. In cases where 
obstructions or restricted areas prevent test station placement, the 
test station must be placed in the closest practical location. Annual 
monitoring of the cathodic protection pipe-to-soil test stations must 
meet Sec. Sec.  192.463 and 192.465 for the Class 1 to Class 3 location 
segment.
    (3) Install and maintain line-of-sight markers visible on the 
pipeline right-of-way, except in agricultural areas or large water 
crossings, such as lakes, where line-of-sight markers are not 
practical. An operator must replace line-of-sight markers as necessary 
and within 30 days after identifying a missing line-of-sight marker.
    (4) Interference surveys to address induced alternating current 
(AC) from parallel electric transmission lines, and other interference 
issues, such as direct current (DC), that may affect the Class 1 to 
Class 3 location segment. If an interference survey finds the 
interference current is greater than or equal to 100 amps per meter 
squared, impedes the safe operation of a pipeline, or may cause a 
condition that would adversely impact the environment or public safety, 
an operator must correct these instances within 15 months of the 
interference survey.
    (5) Depth of cover must conform with Sec.  192.327 for a Class 1 to 
Class 3 location segment or be remediated by adding markers at 
locations that do not meet the requirements of Sec.  192.327 for a 
Class 1 location, lowering the pipe, adding cover, or installing safety 
barriers. Where the depth of cover is less than 24 inches in areas of 
non-consolidated rock, the operator must either lower the pipe or add 
cover over the Class 1 to Class 3 location segment.
    (6) Right-of-way patrols in accordance with paragraphs (a) and (c) 
of Sec.  192.705 at least once per month, with intervals not to exceed 
45 days for Class 1 to Class 3 location segments.

[[Page 65178]]

    (7) Leakage surveys at intervals not exceeding 4\1/2\ months, but 
at least four times each calendar year for Class 1 to Class 3 location 
segments.
    (8) For shorted casings in Class 1 to Class 3 location segments, 
operators must clear the metallic short no later than 1 year after the 
short is identified. For an electrolytic casing short, operators must 
remove the electrolyte from the casing/pipe annular space no later than 
1 year after the short is identified.
    (g) Remote-control or automatic shutoff valves. Mainline valves on 
both sides of Class 1 to Class 3 location segments, and isolation 
valves on any crossover or lateral pipe designed to isolate a leak or 
rupture in a Class 1 to Class 3 location segment, must be operational 
remote-controlled or automatic shutoff valves with pressure sensors on 
each side of the mainline valves. The maximum distance between such 
mainline valves must not exceed 20 miles.
    (1) Valves installed in accordance with this paragraph must be 
closed as soon as practicable after a rupture is identified, but not to 
exceed 30 minutes.
    (2) Valves installed in accordance with this paragraph must be 
operational at all times, controlled by a SCADA system, and monitored 
in accordance with Sec.  192.631.
    (3) Valves installed in accordance with this paragraph must be 
maintained in accordance with Sec. Sec.  192.631(c)(2) and (c)(3), and 
192.745.
    (4) Automatic shutoff valves installed in accordance with this 
paragraph must be set so that, based on operating conditions and 
minimum and maximum flow model gradients, they will fully close within 
a maximum of 30 minutes following rupture identification. Automatic 
shutoff valve set-points must not be less than those required to 
actuate the valve before a downstream remote-control valve actuates. 
The automatic shutoff valve procedure and results for determining 
shutoff times must be reviewed for accuracy at least once each calendar 
year, with intervals not to exceed 15 months.
    (h) Documentation. In addition to the documentation requirements 
specified in Sec.  192.947, each operator must maintain records of all 
actions implemented to comply with paragraph (e) of this section for 
the life of the pipeline, including but not limited to subpart J 
pressure test records in accordance with Sec.  192.517; and records of 
any pipeline assessments, surveys, remediations, maintenance, analyses, 
and other implemented actions.
    (i) Notifications to PHMSA of integrity assessment program for 
class 1 to class 3 location segment changes. Each operator of a gas 
transmission pipeline that uses the integrity assessment program option 
for managing a Class 1 to Class 3 location segment change must notify 
PHMSA electronically in accordance with Sec.  191.22(c)(2).
0
8. Amend Sec.  192.712 by revising the section heading and adding 
paragraph (c) to read as follows:

Sec.  192.712  Analysis of predicted failure pressure and critical 
strain level.

* * * * *
    (c) Dents. To evaluate dents and other mechanical damage that could 
result in a stress riser, an operator must perform an engineering 
critical assessment, as follows:
    (1) Evaluate potential threats for the pipe segment in the vicinity 
of the anomaly or defect including movement, external loading, 
cracking, and corrosion;
    (2) Review high-resolution magnetic flux leakage (HR-MFL) and high-
resolution deformation inline inspection data for damage in the dent 
area and any associated weld region;
    (3) Perform pipeline curvature-based strain analysis using recent 
HR-Deformation inspection data;
    (4) Compare the dent profile between the most recent and previous 
in-line inspections to identify significant changes in dent depth and 
shape;
    (5) Identify and quantify all significant loads acting on the dent;
    (6) Evaluate the strain level associated with the anomaly or defect 
and any nearby welds using Finite Element Analysis, or another 
technology in accordance with paragraph (c)(8) of this section;
    (7) The analyses performed in accordance with this section must 
account for material property uncertainties and model inaccuracies and 
tolerances;
    (8) Dents with geometric strain levels that exceed the critical 
strain must be remediated in accordance with Sec.  192.713 or Sec.  
192.933, as applicable;
    (9) Using operational pressure data, a valid fatigue life 
prediction model, and assuming a reassessment safety factor of 2, 
estimate the fatigue life of the dent by Finite Element Analysis or 
other analytical technique in accordance with this section;
    (10) An operator using other technologies or techniques to comply 
with paragraph (c) of this section must submit advance notification to 
PHMSA in accordance with Sec.  192.18.
0
9. In Sec.  192.903, amend the definition of high consequence area by 
revising paragraphs (1) and (2) to read as follows:

Sec.  192.903  What definitions apply to this subpart?

* * * * *
    High consequence area means an area established by one of the 
methods described in paragraphs (1) or (2) as follows:
    (1) An area defined as--
    (i) A Class 3 location under Sec.  192.5; or
    (ii) A Class 4 location under Sec.  192.5; or
    (iii) Any area in a Class 1 or Class 2 location where the potential 
impact radius is greater than 660 feet (200 meters), and the area 
within a potential impact circle contains 20 or more buildings intended 
for human occupancy; or
    (iv) Any area in a Class 1 or Class 2 location where the potential 
impact circle contains an identified site; or
    (v) Any Class 1 to Class 3 location segment designated as a high 
consequence area in accordance with Sec.  192.618(a).
    (2) The area within a potential impact circle containing--
    (i) 20 or more buildings intended for human occupancy, unless the 
exception in paragraph (4) applies; or
    (ii) An identified site; or
    (iii) Any Class 1 to Class 3 location segment designated as a high 
consequence area in accordance with Sec.  192.618(a).
* * * * *

    Issued in Washington, DC, on September 3, 2020, under authority 
delegated in 49 CFR 1.97.
Alan K. Mayberry,
Associate Administrator for Pipeline Safety.
[FR Doc. 2020-19872 Filed 10-13-20; 8:45 am]
BILLING CODE 4910-60-P