[Federal Register Volume 85, Number 111 (Tuesday, June 9, 2020)]
[Proposed Rules]
[Pages 35240-35254]
[FR Doc No: 2020-11843]

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DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous Materials Safety Administration

49 CFR Parts 191 and 192

[Docket No. PHMSA-2018-0046]
RIN 2137-AF36

Pipeline Safety: Gas Pipeline Regulatory Reform

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

ACTION: Notice of proposed rulemaking.

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SUMMARY: PHMSA is seeking comments on proposed amendments to the
Federal Pipeline Safety Regulations that are intended to ease
regulatory burdens on the construction, maintenance and operation of
gas transmission, distribution, and gathering pipeline systems. The
amendments in this proposal are based on PHMSA's considered review of
public comments, petitions for rulemaking, and an agency initiative to
identify appropriate areas where regulations might be repealed,
replaced, or modified.

DATES: Submit comments by August 10, 2020.

ADDRESS: Submit comments, identified by Docket No. PHMSA-2018-0046,
using any of the following methods:
     Federal eRulemaking Portal: https://www.regulations.gov.
Follow the online instructions for submitting comments.
     Fax: 1-202-493-2251.
     Mail: U.S. DOT Docket Management System, West Building
Ground Floor, Room W12-140, 1200 New Jersey Avenue SE, Washington, DC
20590-0001.
     Hand-deliver/courier: Available between 9:00 a.m. and 5:00
p.m., Monday through Friday, except federal holidays.
    Instructions: All submissions must include the agency name and
docket number for this notice of proposed rulemaking. If you submit
your comments by mail, submit two copies. If you wish to receive
confirmation that PHMSA has received your comments by mail, include a
self-addressed stamped postcard.
    Privacy Act: In accordance with 5 U.S.C. 553(c), the DOT solicits
comments from the public. The DOT posts these comments, without edit,
including any personal information the commenter provides, to http://www.regulations.gov. The complete privacy statement can be reviewed at
http://www.dot.gov/privacy.

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 Freedom of Information Act, and they will not be
placed in the public docket of this notice. Submissions containing CBI
should be sent to Sayler Palabrica at DOT, PHMSA, PHP-30, 1200 New
Jersey Avenue SE, PHP-30, Washington, DC 20590-0001. Any commentary
PHMSA receives that is not specifically designated as CBI will be
placed in the public docket for this matter.

FOR FURTHER INFORMATION CONTACT: Sayler Palabrica, Transportation
Specialist, by telephone at<PHONE_NUMBER>.

SUPPLEMENTARY INFORMATION:
I. Executive Summary
II. Background
III. Request for Input
IV. Proposed Amendments

V. Availability of Standards Incorporated by Reference
VI. Regulatory Analyses and Notices

I. Executive Summary

A. Purpose of This Deregulatory Action

    PHMSA is proposing to amend the Federal Pipeline Safety Regulations
(PSR) at 49 CFR parts 191 and 192 to adopt several actions that ease
regulatory burdens on the construction, operation, and maintenance of
gas transmission, distribution, and gathering pipeline systems. These
proposed amendments include regulatory relief actions identified by
internal agency review, petitions for rulemaking, and public comments
submitted in response to the Department of Transportation (DOT)
infrastructure and regulatory reform notices: ``Transportation
Infrastructure: Notice of Review of Policy, Guidance, and Regulation''
(82 FR 26734; June 8, 2017), and ``Notification of Regulatory Review''
(82 FR 45750; Oct. 2, 2017). PHMSA is requesting input from the public
on the proposed amendments.

B. Proposed Amendments

    PHMSA is proposing the following amendments to parts 191 and 192:
    A. Provide flexibility in the inspection requirements for farm
taps;
    B. Repeal distribution integrity management program (DIMP)
requirements for master meter operators;
    C. Repeal submission requirements for the mechanical fitting
failure (MFF) reports;
    D. Adjust the monetary damage threshold for reporting incidents for
inflation;
    E. Allow remote monitoring of rectifier stations;
    F. Revise the inspection interval for monitoring atmospheric
corrosion on gas distribution service pipelines;
    G. Update the design standard for polyethylene (PE) pipe and raise
the maximum diameter limit;
    H. Revise test requirements for pressure vessels consistent with
American Society of Mechanical Engineers Boiler and Pressure Vessel
Code (ASME BPVC);
    I. Revise welder requalification requirements to provide scheduling
flexibility; and
    J. Extend the allowance for pre-tested short segments of pipe and
fabricated units to pipelines operating at a hoop stress less than 30
percent of the specified minimum yield strength (SMYS) and above 100
pounds per square inch (psi).

C. Costs and Benefits

    In accordance with 49 U.S.C. 60102, Executive Order (E.O.) 12866,
and DOT policy, PHMSA has prepared an initial assessment of the costs
and benefits of these proposed changes as well as reasonable
alternatives. PHMSA has released the preliminary regulatory impact
analysis (PRIA) concurrent with this NPRM for public review and
comment, and it is available in the docket.
    The PRIA uses an analysis period of twenty years and the
incremental cost savings are assumed to accrue on an ongoing basis.
Most of the proposed revisions are deregulatory that are expected to
reduce unnecessary regulatory burdens, increaseflexibility and
efficiency, and add clarity to existing regulations. PHMSA estimates
the value of the total quantified annualized cost savings is
approximately $129 million (at a discount rate of 7 percent) or
approximately $132 million (at a discount rate of 3 percent).\1\ PHMSA
describes the benefits of this proposed rule qualitatively and does not
anticipate that the revisions will result in an adverse impact on
pipeline safety.
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    \1\ Both values are in 2018 dollars.
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    The primary economic consequences of the proposed deregulatory
actions in this rule are cost savings. The largest quantified cost
savings are due to the amendments related to farm taps and atmospheric
corrosion (AC). The remaining amendments provide benefits largely of
convenience, clarity and simplicity. The total estimated economic
effects of the proposed rule are summarized in the table below (Table
1). PHMSA provided annualized estimates of cost savings where
available.

            Table 1--Total Estimated Discounted Cost Savings
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                                                          Estimated cost
                        Category                              savings
                                                            (millions)
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Total (20 years; discounted at 7 percent)...............        $1,371.4
Total (20 years; discounted at 3 percent)...............         1,965.3
Annualized (discounted at 7 percent)....................          129.45
Annualized (discounted at 3 percent)....................         132.101
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II. Background

    On January 30, 2017, the President issued E.O. 13771, ``Reducing
Regulation and Controlling Regulatory Costs.'' E.O. 13771 explained the
executive branch's regulatory policy to be prudent and financially
responsible in the expenditure of funds, from both public and private
sources, and to manage the compliance burdens from federal regulations.
    On February 24, 2017, the President issued E.O. 13777, ``Enforcing
the Regulatory Reform Agenda'' (82 FR 12285), which established a
federal policy to ``alleviate unnecessary regulatory burdens placed on
the American people.'' E.O. 13777 required that each federal agency
establish a Regulatory Reform Task Force (RRTF) to evaluate existing
regulations and ``make recommendations to the agency head regarding
their repeal, replacement, or modification.'' Each RRTF must identify
unnecessary, outdated, inneffective regulations and those that impose
costs that exceed benefits.
    On March 28, 2017, the President issued E.O. 13783, ``Promoting
Energy Independence and Economic Growth'' (82 FR 16093; Mar. 28, 2017),
to promote the clean and safe development of the Nation's energy
resources by eliminating unnecessary regulatory burdens on energy
production, economic growth, and job creation. E.O. 13783 tasked
agencies to review existing regulations, guidance, and orders that
potentially burden the development or use of domestically produced
energy resources. Specifically, agencies must look for impacts on
siting, permitting, production, utilization, transmission, or delivery
of energy resources and encourage the development of recommendations to
reduce or eliminate potential burdens.
    DOT issued two notices in response to the three executive orders
soliciting regulatory reform ideas from the public. The first notice
(82 FR 26734; June 8, 2017) requested public comment on existing
regulations that may be obstacles to transportation infrastructure
projects. DOT received more than 200 comments in the transportation
infrastructure docket, including 6 comments that are relevant to the
PSR.\2\ The second notice (82 FR 45750; Oct. 2, 2017) requested comment
on existing rules and other agency actions that may be eligible for
repeal, replacement, suspension, or modification without compromising
safety. DOT asked the public to identify agency actions that eliminate
jobs or inhibit job creation; are outdated, unnecessary, or
ineffective; impose costs that exceed benefits; create a serious
inconsistency or otherwise interferes with regulatory reform
initiatives and policies; could be revised

to use performance standards in lieu of design standards; or that
potentially unnecessarily encumber energy production. After a 30-day
comment period, DOT re-opened the comment period until December 1,
2017, (82 FR 51178; Nov. 3, 2017). Of the nearly 3,000 public comments
received, approximately 30 were related to the federal PSR.\3\
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    \2\ Docket No. DOT-OST-2017-0057.
    \3\ Docket No. DOT-OST-2017-0069.
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    To support DOT's regulatory reform efforts, PHMSA's Office of
Pipeline Safety (OPS) reviewed, considered, and identified existing
regulations that could be improved, revised, repealed, or streamlined.
OPS also considered the public comments submitted in response to DOT's
June 8, 2017, notice soliciting comments about transportation
infrastructure, DOT's October 2, 2017, public notice soliciting
comments on regulatory reform, and petitions for rulemakings. Some of
the comments submitted in response to these notices are addressed in
this proposed rule, such as the proposed amendments to reporting
requirements, farm tap maintenance, atmospheric corrosion monitoring.
Other comments will be addressed in other rulemaking projects, or
through revised policy and guidance. Finally, some ideas proposed in
comments are under longer-term technical review or have been rejected
due to safety concerns.

III. Request for Input

    PHMSA is seeking public comments on the regulatory reform actions
proposed in this notice. PHMSA will consider all relevant, substantive
comments but encourages interested parties to submit comments that: (1)
Identify the proposed amendments being commented on and the appropriate
section numbers; (2) provide justification for their support or
opposition to the proposed amendments, especially data on safety risks
and cost burdens; and (3) provide specific alternatives if appropriate.

IV. Proposed Amendments

Distribution Integrity Management Program (DIMP)

    On December 4, 2009, PHMSA issued a final rule, titled ``Pipeline
Safety: Integrity Management Program for Gas Distribution Pipelines''
(74 FR 63905), creating 49 CFR part 192, subpart P. The scope of
subpart P, defined at Sec.  192.1003, requires certain gas distribution
operators to develop and implement integrity management (IM) programs.
PHMSA is proposing two revisions to DIMP requirements to ease or
eliminate regulatory burdens on certain gas distribution operators. The
first revision is to allow operators of individual service lines
directly connected to transmission or regulated gathering lines
(commonly known as ``farm taps'') the option of managing the
maintenance of pressure regulating devices under either Sec.  192.740
or their DIMP plan in accordance with subpart P. As part of this
amendment, the proposed rule would also exempt farm taps originating
from unregulated gathering and production pipelines from DIMP, Sec.
192.740, and incident and annual reporting requirements in part 191.
Second, PHMSA is also proposing to exempt master meter operators from
DIMP requirements due to their simplicity.

A. Farm Taps (Sections 191.11, 192.740, 192.1003)

    PHMSA proposes to revise Sec. Sec.  192.740 and 192.1003 to give
operators the choice to manage inspections of pressure regulators
serving farm taps under either their DIMP or by following the
inspection requirements at Sec.  192.740. A ``farm tap'' is the common
name for an individual gas service line directly connected to a gas
transmission, production, or gathering pipeline. The term farm tap is
not a regulatory definition used in the PSR, however a portion of a
farm tap between the first aboveground point where downstream piping
can be isolated from source piping (e.g. a valve or regulator inlet)
and either the outlet of the customer's meter or the connection to a
customer's piping, whichever is further downstream, may be a service
line regulated under part 192 (see the definition of a ``service line''
in Sec.  192.3).
    On January 23, 2017, PHMSA published a final rule that added Sec.
192.740, ``Pressure regulating, limiting, and overpressure protection--
Individual service lines directly connected to production, gathering,
or transmission pipelines'' (82 FR 7972). Section 192.740 includes
maintenance requirements for regulators and overpressure protection
equipment for an individual service line that originates from a
transmission, gathering, or production pipeline (i.e., a farm tap).
Such devices must currently be inspected and tested at least once every
3 calendar years, not to exceed 39 months. Further, PHMSA revised the
DIMP applicability regulations at Sec.  192.1003 to exclude farm taps
from DIMP requirements. PHMSA amended part 192 as such to create
uniform compliance requirements for farm taps and decrease the burden
of meeting the DIMP requirements. However, operators who historically
had included farm taps in their DIMP plan found it burdensome to remove
those facilities from their plan and reevaluate the risks under a new
program.
    DOT received joint comments on its regulatory reform notice (82 FR
45750; Oct. 2, 2017) from the American Gas Association (AGA), the
American Petroleum Institute (API), and Interstate Natural Gas
Association of America (INGAA) (collectively, ``the Associations''),
which recommended that PHMSA revise Sec. Sec.  192.740 and 192.1003 to
allow operators the flexibility to address the maintenance of farm taps
under either of these regulatory requirements. After considering those
comments, PHMSA is proposing to revise Sec. Sec.  192.740 and 192.1003
to give operators of farm taps originating from regulated source
pipelines the choice to include those farm taps in their DIMP or manage
the maintenance of the associated pressure regulators under the
requirements at Sec.  192.740. PHMSA has determined that compliance
with either Sec.  192.740 or DIMP provides an equivalent level of
safety. PHMSA, therefore anticipates that this action will maintain
pipeline safety while reducing regulatory burden. As an alternative to
the proposal submitted in public comments, PHMSA also evaluated the
alternative of repealing Sec.  192.740 and reinstating DIMP
requirements for farm taps. However, that alternative only shifts the
problem onto transmission and gathering operators with no safety
benefit.
    Finally, PHMSA proposes to exempt farm taps branching off of
unregulated gathering or production pipelines from annual reporting
(Sec.  191.11), farm tap regulator maintenance (Sec.  192.740), and
DIMP (part 192, subpart P). Any portion of a farm tap that meets the
definition of a service pipeline must still comply with all other
requirements in parts 191 and 192 applicable to service pipelines, even
if the source of the service pipeline is not regulated by PHMSA. For
example, an entity that operates a production pipeline with an attached
farm tap must have an operator identification number in accordance with
Sec.  191.22 and must submit incident reports for incidents caused by
failures on the service pipeline (Sec.  191.9). While the operator's
production pipeline is exempt from part 191 (see Sec.  191.1(b)(4)),
any facility that meets the definition of a service line is a regulated
distribution pipeline and therefore does not fall within the exemption
for unregulated gathering and production pipelines.

B. Master Meter Operators (Sections 192.1003, 192.1015)

    PHMSA is proposing to revise Sec. Sec.  192.1003 and 192.1015 to
exempt master meter operators from DIMP requirements. A ``master meter
system'' is defined at Sec.  191.3 as a pipeline system for
distributing gas where the operator purchases metered gas from an
outside source for resale through a gas distribution pipeline system.
Examples of master meters include owners of apartment complexes or
mobile home parks who sell gas to tenants. Unlike most gas distribution
operators, delivering gas is typically not a master meter operator's
primary business.
    As a result of the agency's internal review, PHMSA is proposing to
exempt master meter operators from DIMP requirements by revising the
applicability of subpart P at Sec.  192.1005 and revising Sec.
192.1015. When DIMP was first proposed in 2008 (73 FR 36015), PHMSA
recognized that master meter systems tend to be operated by small
entities with simple systems compared to normal gas distribution
operators. Section 192.1015 was intended to provide a simplified set of
requirements that master meter operators could easily implement and
benefit from.
    Through inspections, PHMSA and its state partners have seen that
master meter operators have had significant difficulties implementing
these simplified DIMP requirements effectively. PHMSA's state-federal
DIMP team has noted that a significant amount of inspection and
maintenance effort was being used to improve DIMP compliance among
master meter operators. Despite these efforts, inspection data
voluntarily submitted by some states shows that approximately half of
master meter operators inspected between 2014 and 2017 did not have an
acceptable DIMP in place before the compliance deadline of August 2,
2011, and for any given requirement 10-20% of master meter operators
were not in compliance. PHMSA believes that this effort would be better
used to effectively implement other basic requirements.
    Even when properly implemented, DIMP principles that are effective
for larger operators do not have the same value for comparatively
simple master meter systems within a limited geographical area. The
proposed DIMP rule noted that master meter systems often include only
one type of pipe, a single operating pressure, and no equipment other
than pipe, meters, regulators, and valves. For these small and simple
systems, a management system is not required to integrate data and
information in order to identify risk mitigation strategies and
actions. PHMSA's experience indicates that the analysis and
documentation requirements of DIMP has had little safety benefit for
this type of operator. PHMSA, state inspectors and subject matter
experts agree that focusing on more fundamental risk mitigation
activities (e.g., Sec.  192.605 Procedural manual for operations,
maintenance, and emergencies, Sec.  192.613 continuing surveillance,
and Sec.  192.617 investigations of failures) has more safety benefits
than implementing a DIMP for this class of operators. Due to the
implementation issues identified by PHMSA and state inspectors, PHMSA
expects that exempting master meter operators from subpart P would
result in cost savings for master meter operators without negatively
impacting safety. PHMSA believes there are even potential safety
benefits to allowing operators and inspectors to instead prioritize the
most pertinent compliance activities specific to master meter systems.
    Master meter operators would still be subject to the rest of the
pipeline safety regulations at part 192, such as the operations and
maintenance requirements at subpart L and subpart M, the continuing
surveillance requirements at Sec.  192.613 and the failure
investigation requirement at Sec.  192.617. PHMSA believes those
regulations adequately manage pipeline integrity risks for master meter
operators with less burden. In consideration of the proposed DIMP
exemption, PHMSA also requests public comment on whether PHMSA should
repeal the incident reporting exception for master meter operators
(Sec.  191.9 (c)), including specific safety issues that would merit
monitoring through incident reporting requirements for such facilities.

Reporting and Information Collections

C. Mechanical Fitting Failure Reporting (Sections 191.12, 192.1009)

    PHMSA is proposing to remove Sec. Sec.  191.12 and 192.1009,
eliminating the requirement for operators to submit mechanical fitting
failure (MFF) reports through DOT Form PHMSA F-7100.1-2. Operators
would still be required to submit incident reports, which include
almost all of the information on the MFF form, for releases from
mechanical fittings that meet the definition of an incident at Sec.
191.3. PHMSA also proposes to revise the gas distribution annual report
form (DOT Form PHMSA F 7100.1) to include a count of MFFs. This issue
was raised in comments submitted in response to the notice of
regulatory reform from the Associations, the Gas Piping Technology
Committee (GPTC), and the West Virginia Oil and Natural Gas Association
(WVONGA), identifying this reporting requirement as an unnecessary and
burdensome information collection.
    On February 1, 2011, PHMSA issued the final rule, ``Pipeline
Safety: Mechanical Fitting Failure Reporting Requirements,'' (76 FR
5499), adding Sec. Sec.  191.12, 192.1001, and 192.1009 to the
regulations. Section 191.12 sets forth the requirement for operators to
report MFFs through DOT Form PHMSA F-7100.1-2. Section 192.1001 defines
a ``mechanical fitting.'' Section 192.1009 requires distribution
pipeline operators to submit a MFF report to PHMSA almost every time
there is a release from a mechanical fitting, the vast majority of
which are low-consequence events that do not meet the definition of an
incident at Sec.  191.3. These changes were initially proposed as a
result of investigations of incidents caused by improperly designed or
installed mechanical fittings. The intent of collecting this data was
to determine the frequency of mechanical fitting failures and identify
the most common characteristics of those failures.
    Similar to the incident report form, the MFF form \4\ requires
operators submit information on the design and installation of the
failed fitting and the apparent cause of the leak. The form also
includes manufacturing information; however, this is commonly not known
by the operator. Unlike incident reports, which are required for events
that meet the criteria defined in Sec.  191.3, MFF reports are required
for each MFF that results in a ``hazardous leak'', defined at Sec.
192.1001, a much broader category of events. As a result, PHMSA
currently collects approximately 15,000 MFF reports each year, compared
to approximately 100 gas distribution incidents due to all causes. This
has allowed PHMSA to collect and analyze a much larger volume of
detailed information regarding MFFs than would be possible from
incident reports alone. PHMSA publishes a report on the information
collected and its analysis of the information received annually, which
is available online.\5\
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    \4\ PHMSA F-7100.1-2.
    \5\ https://www.phmsa.dot.gov/pipeline/gas-distribution-integrity-management/dimp-performance-measures-data-analysis-procedure-report.
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    After over 8 years of collecting and analyzing MFF information,
PHMSA has determined that further collection of

MFF reports is no longer necessary. PHMSA's past analysis of the MFF
data has confirmed the Agency's initial expectations regarding the
frequency and characteristics of MFFs when the information collection
activity was initiated. Further, PHMSA has not identified any
statistically significant trends in the MFF report data over this time
period. Finally, improvements in fitting design and operator practices
have reduced the risks of these devices on newer installations. PHMSA,
therefore, has determined it no longer needs to collect detailed
information on thousands of MFFs that do not result in incidents. In
the future, a combination of gas distribution incident reports and
PHMSA's proposal to add a count of MFFs on gas distribution annual
reports will adequately meet PHMSA's information needs with regards to
the safety of mechanical fittings.
    PHMSA's proposal to replace the requirement to submit a full MFF
report with a count of MFFs on the gas distribution annual report \6\
results in a net reduction in reporting burden for each event, without
a significant loss of useful information to PHMSA. In the future, a
combination of incident reports and a count of MFFs on annual reports
will continue to provide PHMSA with adequate information regarding the
safety of mechanical fittings. If a MFF results in an incident, then
the operator must submit a gas distribution incident report form,\7\
which currently collects almost all of the data fields on the MFF
form.\8\ A count of MFF on operators' annual reports allows PHMSA to
continue to collect information on trends in the number of MFFs
nationally and compare failure rates among operators, which is useful
information for PHMSA and state pipeline safety programs.
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    \6\ DOT Form PHMSA F 7100.1-1 (rev 1/30/2017).
    \7\ DOT Form PHMSA F 7100.1 (rev 10/2014)).
    \8\ DOT Form PHMSA F 7100.1-2 (rev 10/2014).
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    PHMSA has determined that requiring a detailed MFF report for each
MFF is no longer necessary. PHMSA can meet its information needs with
substantially less burden through existing incident reporting
requirements and PHMSA's proposal to revise the gas distribution annual
report form to include a count of MFFs that result in hazardous leaks.
Since PHMSA no longer requires the information on the MFF form for
failures that do not lead to incidents, the proposed change eliminates
an unnecessary reporting burden and would have no impact on safety.

D. Monetary Threshold for Incident Reporting (Section 191.3)

    PHMSA is proposing to revise the definition of an ``incident'' at
Sec.  191.3 to adjust the monetary damage threshold for inflation.
PHMSA is proposing to raise the reporting threshold for incidents that
result in property damage to $122,000, consistent with inflation since
1984. The property damage criterion includes losses to the operator and
others but excludes the cost of lost gas. Any incident that results in
one or more of the other criteria (a fatality, an injury that requires
in-patient hospitalization, releases over three million cubic feet of
gas, or is significant in the judgment of the operator) would still be
defined as an incident that must be reported regardless of how much
property damage occurs. PHMSA intends to base any finalized version of
this provision on the price level at the time of publication of the
final rule.
    On May 3, 1984, PHMSA's predecessor agency, the Research and
Special Programs Administration, added a definition for an ``incident''
at Sec.  191.3 (49 FR 18960). The definition provides criteria that
requires operators to report specific events to PHMSA. The 1984
definition of an incident included, among other things, a release of
gas that results in estimated property damage of $50,000 or more.
Today, over 30 years later, operators must still submit an incident
report for any release that results in estimated property damage of
$50,000 or more.
    One of the most frequent comments submitted in response to the
notice of regulatory reform addressed the $50,000 monetary damage
threshold for reporting gas pipeline incidents and hazardous liquid
pipeline accidents. The Associations, GPTC, and the GPA Midstream
Association \9\ submitted comments in response to the notice of
regulatory reform that recommended an increase in the monetary damage
threshold for reporting gas pipeline incidents and hazardous liquid
pipeline accidents. Based on the average annual Consumer Price Index
(CPI) from the Bureau of Labor Statistics of the U.S. Department of
Labor, $50,000 in 1984 is $122,000 in 2019 dollars.\10\ The current
damage threshold requires incidents that would not have been reported
in 1984 to be reported to PHMSA due to inflation in property,
equipment, and repair costs.
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    \9\ GPA, formerly the Gas Processors Association.
    \10\ This analysis is based on the CPI for All Urban Consumers
(CPI-U) from the Bureau of Labor Statistics, accessed via https://data.bls.gov/cgi-bin/cpicalc.pl.
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    The proposed revision to the monetary damage threshold brings the
incident reporting criteria in-line with the 1984 threshold in
inflation-adjusted terms. Based on a review of previous incident
reports, adjusting the figure for inflation would decrease the number
of events reportable as incidents by approximately one fourth, and
reduce those reportable due to only the property-damage criterion by
almost half. This rulemaking assumes the threshold set 35 years ago is
still appropriate for today once it is adjusted for inflation; however,
since the original rulemaking 35 years ago, an improved safety record
has decreased the number of significant events, and the safety
information needs may have changed. PHMSA seeks comment on whether the
level of safety information needed from property damage only incident
reporting should be updated to align with inflation, and the extent to
which retaining a defacto lower threshold after inflation would provide
beneficial information on contributing risk factors and incident
trends.
    PHMSA intends to periodically update the monetary damage threshold
on a regular basis in the future, potentially biennially. Future
updates would be based on the same formula used for this adjustment:
[GRAPHIC] [TIFF OMITTED] TP09JN20.002

    Where Tn is the revised damage threshold, Tp is the previous damage
threshold, CPIn is the average CPI-U for the past calendar year, and
CPIp is the average CPI-U used for the previous damage threshold. PHMSA
could subsequently update the monetary damage threshold in accordance
with this formula either through notice and comment rulemaking, a
direct final rule, notice on the PHMSA public website, or other means.
This method is similar to the method that the Federal Railroad
Administration uses to update the criteria for reporting accidents/
incidents at 49 CFR 225.19 and Appendix B to part 225. PHMSA seeks
comments on the appropriate method and frequency for future updates to
the monetary damage threshold.
    PHMSA also considered revising the monetary damage threshold by
eliminating the monetary damage threshold entirely and only require
reporting incidents that meet one of the other criteria. Ultimately,
PHMSA chose to propose a monetary damage threshold derived by adjusting
the current value for inflation since 1984. This approach aligns with
the intent of the 1984 monetary damage threshold and was

supported in public comments submitted in response to the notice of
regulatory reform. PHMSA determined that eliminating the monetary
threshold was not appropriate. Repealing that criterion would eliminate
approximately half of all incident reports, significantly reducing the
amount of safety data available to PHMSA, state pipeline safety
programs, operators, and the public.

Corrosion Control

    Virtually all hazardous liquid and most natural gas transmission
pipe in service today is made of steel. This steel, when not otherwise
protected, reacts with its environment and can deteriorate over time.
Under certain conditions, unprotected metal can corrode, causing gas
leaks that can threaten public safety. To guard against this, the PSR
requires, with some exceptions, cathodic protection and protective
coatings to mitigate corrosion risks on pipelines. Cathodic protection
works like a battery, running an electrical current across the buried
pipeline using devices called rectifiers. The electrical current
prevents the metal surface of the pipe from reacting with its
environment. If the current is sufficient, cathodic protection can
control corrosion threats.
    Subpart I of part 192 establishes requirements for corrosion
control and remediation for natural gas pipelines. This subpart also
establishes inspection intervals for testing and repairing systems as
necessary to bring them into compliance. PHMSA is proposing two
amendments related to corrosion control. PHMSA is proposing to clarify
that cathodic protection rectifiers can be monitored remotely and to
revise the requirements for assessing atmospheric corrosion on
distribution service pipelines.

E. External Corrosion Control: Monitoring (Section 192.465)

    PHMSA is proposing to revise Sec.  192.465(b), ``External corrosion
control: Monitoring,'' to clarify that operators may monitor rectifier
stations remotely. As discussed earlier, rectifiers are devices that
direct an electrical current on a pipeline to prevent external
corrosion.
    Section 192.465(b) requires regular inspection of rectifiers on gas
pipelines to ensure that they are working correctly. Advances in
technology make it possible to monitor the proper operation of these
electrical systems remotely, but it is not clear in the regulations if
this is permissible. PHMSA is proposing to revise Sec.  192.465(b) to
clarify that operators may inspect rectifier stations directly onsite
or by way of remote monitoring technologies. This proposed rule also
clarifies that, at a minimum, such an inspection consists of recording
amperage and voltage measurements. PHMSA is considering a similar
revision for monitoring rectifier stations on hazardous liquid
pipelines in a separate rulemaking.
    Remote monitoring equipment must be properly maintained in order to
function safely and as intended. PHMSA's experience has shown that
rectifiers, often located in remote areas, can be subject to damage
from a variety of sources, including natural forces and vandalism. If
an operator chooses to monitor a rectifier remotely, PHMSA proposes to
require operators to physically inspect that station whenever they
conduct a cathodic protection test pursuant to Sec.  192.465(a). For
transmission pipelines and distribution mains, this will occur once
each calendar year, concurrent with existing inspection activities
required at Sec.  192.465(a).

F. Atmospheric Corrosion: Monitoring (Sections 192.481, 192.1007,
192.1015)

    PHMSA is proposing to revise Sec.  192.481 to establish a separate
atmospheric corrosion reassessment interval for gas distribution
service pipelines. Currently, all onshore gas pipelines that are
exposed to the atmosphere must be inspected once every 3 years, not to
exceed 39 months. PHMSA proposes a maximum inspection interval for
service lines of once every 5 calendar years, not to exceed 63 months,
unless atmospheric corrosion was identified on the last inspection.
PHMSA also proposes to keep the current inspection interval on service
lines with observed corrosion; if an operator identifies atmospheric
corrosion on a service line during an inspection, then the interval for
the subsequent inspection would be once every 3 years, not to exceed 39
months. If no atmospheric corrosion is identified on a subsequent
inspection, then operators would be permitted to revert to the 5-year
inspection interval. PHMSA is not aware of any incidents caused by
atmospheric corrosion on distribution service lines since at least 1986
\11\ and does not anticipate a decrease in safety from this change.
---------------------------------------------------------------------------

    \11\ 1986 is the earliest year available in the ``Pipeline
Incident Flagged Files'' dataset. https://www.phmsa.dot.gov/data-and-statistics/pipeline/pipeline-incident-flagged-files.
---------------------------------------------------------------------------

    Also with regard to atmospheric corrosion, consistent with comments
on the notice of regulatory reform, PHMSA proposes to clarify that
existing requirements to consider corrosion under DIMP include the
consideration of atmospheric corrosion risks. PHMSA would expect
operators of service lines in high-corrosion environments to consider
atmospheric corrosion in their evaluation of risks under DIMP and
conduct atmospheric corrosion inspections more frequently than the
minimum requirements in this section.
    Comments on the notice of regulatory reform from the Associations,
APGA, GPTC, and WVONGA recommended that PHMSA revise the atmospheric
corrosion inspection requirements for distribution pipelines. The
Associations commented that PHMSA should allow operators of
distribution pipelines to manage atmospheric corrosion based on the
operator's assessment of the risks in accordance with their DIMP plans.
Alternatively, APGA recommended simply establishing an inspection
interval of 5 years, not to exceed 63 months for all distribution
pipelines, which would allow operators to coordinate atmospheric
corrosion assessments with leakage surveys (Sec.  192.723), which also
occur at an interval of 5 years, not to exceed 63 months.
    PHMSA considered each of those suggestions as alternatives, and the
proposed rule integrates aspects of each. The proposed rule establishes
a maximum inspection interval of 5 years for distribution service lines
without observed corrosion. PHMSA agreed with the rationale for the
benefits of aligning atmospheric corrosion reassessment intervals with
those for leakage surveys in Sec.  192.723 presented in comments from
APGA. Additionally, PHMSA has approved state waivers in the past that
have allowed certain operators to perform both atmospheric corrosion
and leakage surveys on a 4-year interval outside of business districts
and subject to certain conditions. The most recent of these was for
North Western Energy in South Dakota, issued March 2, 2019,\12\ and
others have been approved in the past in Illinois. PHMSA has not
observed an increase in leaks or incidents in these locations,
confirming that a longer atmospheric corrosion inspection interval is
supported in areas with low atmospheric corrosion risk.
---------------------------------------------------------------------------

    \12\ Additional information is available in the docket for this
action (PHMSA-2019-0052) at https://www.regulations.gov/docket?D=PHMSA-2019-0052.
---------------------------------------------------------------------------

    Unlike both other alternatives, which apply to all distribution
pipelines, PHMSA limited the revised reassessment interval to
distribution service lines. Operators have reported

atmospheric corrosion incidents on distribution mains, and compared to
mains, service lines tend to be smaller, have lower flow, and are
generally built of thicker wall pipe. Additionally, aboveground
distribution facilities other than service lines must be inspected
frequently under other sections of the PSR, providing ample opportunity
to note and correct any corrosion issues.
    PHMSA recognizes that not all environments face the same
atmospheric corrosion risks. However, based on inspection results and
field experience, PHMSA determined that establishing a maximum
inspection interval, rather than an open-ended reference to DIMP, is
necessary to ensure that atmospheric corrosion on distribution
facilities is being adequately monitored and remediated before it leads
to a failure. The proposed maximum interval of five years was supported
in public comments and will allow operators of gas distribution
pipelines with low atmospheric corrosion risks to realize cost savings
from less-frequent inspections and the ability to schedule corrosion
inspections and leakage surveys concurrently. Since the primary cost
savings comes from coordinating inspection activity, PHMSA was not
persuaded that there is significant benefit to allowing atmospheric
corrosion inspection intervals longer than the leakage survey interval
in Sec.  192.723(b)(2). The proposed requirement to evaluate
atmospheric corrosion risks under DIMP and the shorter inspection
interval for pipelines with observed corrosion will ensure that
operators of service pipelines with atmospheric corrosion threats take
appropriate action to maintain the integrity of those pipelines.
    The proposed amendments to Sec. Sec.  192.1007 and 192.1015 clarify
that consideration of corrosion under DIMP requires consideration of
atmospheric corrosion risks. When evaluating atmospheric corrosion
risks under DIMP, PHMSA expects operators to evaluate environmental
risk factors and the operating history of the service lines.
Environmental risk factors for atmospheric corrosion include proximity
to coasts, atmospheric moisture, salinity, and corrosive pollution.
Relevant operational risks include a history of leaks, incidents, and
evidence of atmospheric corrosion on previous inspections. PHMSA
expects operators of distribution lines with higher risks due to
atmospheric corrosion threats (e.g., humid, coastal environments, or a
history of leaks caused by atmospheric corrosion) to take mitigative
action, such as more frequent inspection or maintenance activities, as
part of their DIMP plans and accurately and completely document such
actions.

Standards Incorporated by Reference

G. Plastic Pipe (Sections 192.7, 192.121, Appendix B)

    PHMSA is proposing to update Sec. Sec.  192.7, 192.121 and appendix
B to part 192 to incorporate by reference the 2018a edition of the ASTM
International (ASTM, formerly the American Society for Testing and
Materials) document, ``Standard Specification for Polyethylene (PE) Gas
Pressure Pipe, Tubing, and Fittings'' (ASTM D2513-18a).\13\ ASTM D2513
is the standard that specifies the design of PE pipe and fittings.
After reviewing the standard, PHMSA determined that the improvements
since the 2012 edition, which is currently incorporated by reference,
justify incorporating by reference the 2018a edition. These
improvements include more specific testing requirements for measuring
resistance to UV exposure and clarifying the applicability of the
document to all fuel gas piping. Consistent with the updated ASTM
standard, PHMSA also proposes to raise the diameter limit for using a
design factor of 0.4 on PE pipe from 12 inches to 24 inches and add
entries for those sizes to the PE minimum wall thickness table at Sec.
192.121(c)(2)(iv). The Plastics Pipe Institute, representing
manufacturers of plastic pipe and components, and a citizen commenter
submitted comments in response to the notice of regulatory reform
addressing this issue. PHMSA reviewed ASTM D2513-18 and determined that
PE pipe with diameters up to 24 inches that are manufactured in
accordance with the standard and the design and construction
requirements in part 192 are acceptable for use in gas pipeline
systems.
---------------------------------------------------------------------------

    \13\ ASTM D2513-18a, Standard Specification for Polyethylene
(PE) Gas Pressure Pipe, Tubing, and Fittings, ASTM International,
West Conshohocken, PA, August 1, 2018, www.astm.org.
---------------------------------------------------------------------------

    Currently, PHMSA incorporates by reference ASTM D2513-12ae1 into
item I, appendix B to part 192. While Table 2 of ASTM D2513-12ae1
includes outside diameter specifications for pipe sizes up to 24-inch
nominal diameter, Table 4 only includes wall thickness specifications
for pipe sizes up to 12-inch nominal diameter. Since plastic pipe must
be manufactured in accordance with a listed specification, it is not
clear if and when sizes above 12 inches are allowed. PHMSA's proposal
to adopt ASTM D2513-18 and revise the minimum wall thickness table at
Sec.  192.121(c)(2)(iv) would resolve this discrepancy.
    PHMSA also proposes to clarify and improve requirements for joining
procedures in Sec. Sec.  192.281 and 192.283 to allow operators
additional flexibility when developing such procedures and to improve
safety. Specifically, PHMSA proposes to incorporate by reference the
2019 edition of ASTM F2620, ``Standard Practice for Heat Fusion Joining
of Polyethylene Pipe and Fittings'' and make revisions to Sec. Sec.
192.281 and 192.285 to clarify that procedures that are demonstrated to
provide an equivalent or superior level of safety as ASTM F2620 are
acceptable. This amendment addresses concerns raised by a petition for
reconsideration submitted by AGA on August 23, 2019 \14\ in response to
the final rule titled ``Pipeline Safety: Plastic Pipe Rule'' issued on
November 20, 2018 (83 FR 58694).
---------------------------------------------------------------------------

    \14\ See Docket Number PHMSA-2019-0200. https://www.regulations.gov/docket?D=PHMSA-019-0200.
---------------------------------------------------------------------------

    In the final rule, PHMSA amended Sec. Sec.  192.281 and 192.285 to
require PE heat-fusion joining procedures meet the requirements of the
2012 edition of ASTM F2620. Heat fusion is a common method for joining
plastic pipe and components. In heat fusion, a worker prepares the
surfaces of the pipe or fittings being joined, heats the surfaces using
a heating element, and then presses the pipe or fittings together with
sufficient force for the molten material to mix and fuse as it cools.
ASTM F2620 describes procedures for making socket fusion, butt fusion,
and saddle fusion joints. The document describes requirements for the
selection, preparation, and maintenance of joining equipment; preparing
surfaces for joining; specified heating temperatures and times; joining
forces; and cooling procedures. The standard also includes
considerations for joining in cold weather and criteria for evaluating
the quality of fusion joints.
    AGA raised concerns that the language in these sections as written
would require operators to requalify safe procedures that were
qualified in the past in accordance with Sec.  192.283. AGA
specifically mentioned that many operators use heat fusion procedures
published by the Plastic Pipe Institute (PPI), a trade association
representing manufacturers of plastic pipe and fittings, such as PPI
TR-33 and PPI TR-41. While PHMSA noted in the preamble of the final
rule that PHMSA would find a joining method acceptable if ``an operator
can demonstrate the differences are sound and provide

equivalent or better safety compared to ASTM F2620,'' AGA raised
concerns that the regulatory text itself does not necessarily provide
this flexibility, and suggested PHMSA allow the use of other qualified
procedures, such as PPI TR-33 and PPI TR-41, under Sec.  192.283.
    After reviewing AGA's petition, PHMSA proposes to revise Sec. Sec.
192.281 and 192.285 consistent with the intent stated in the preamble
of the plastic pipe rule. PHMSA proposes to revise Sec.  192.281(c) to
allow an alternative written procedure to ASTM F2620 provided that the
operator can demonstrate that it provides an equivalent or superior
level of safety and has been proven by test or experience to produce
strong, gastight joints. In other words, the procedure produces joints
that do not allow gas to leak, are at least as strong as the pipe being
joined, are designed to handle the expected environment and internal
and external loads, and has been validated by formal testing in
accordance with Sec.  192.283 and applicable standards incorporated by
reference or through several years of operational experience without
leaks or failures.
    As described in the preamble to the plastic pipe final rule, PHMSA
expect operators to document the differences from ASTM F2620 and
demonstrate how the alternate procedures provide an equivalent or
superior level of safety. Similarly, PHMSA proposes to revise Sec.
192.285(b)(2)(i) to allow other written procedures that have been
proven by test or experience to produce strong, gastight joints. PHMSA
is not implementing AGA's proposed language to allow any procedure
qualified in accordance with Sec. Sec.  192.281 and 192.285 in order to
retain the intended safety benefits of adopting ASTM F2620. If the
operator's procedures are found to be lacking in any way--such as
changes to surface preparation, heating temperatures, fusion pressures,
or cooling times that lack adequate technical justification--they would
still be unacceptable.
    Related to this issue, PHMSA also proposes to incorporate by
reference the 2019 edition of ASTM F2620. The updated edition of the
standard clarifies the relationship between ASTM F2620 and the PPI
documents referenced in AGA's petition in a new Note 1 in Section 1.2.
In addition to clarifying some of AGA's concerns, the 2019 edition of
the standard includes a number of incremental improvements to safety
and editorial clarity. These improvements include a new section 6.4
that requires additional precautions during pipe cutting to prevent the
introduction of contaminants that can weaken the joint and a new
section X4.2 that references the required test method for qualifying
plastic pipe joiners in Sec.  192.285. Additionally, the 2019 edition
revises the recommended precautions for preventing or removing
contamination during pipe cutting in section X1.7.1 to clarify that any
soap is a contaminant and that contamination may be introduced during
cutting, and to require cleaning of the outer and inner surface of the
pipe in addition to the end. These changes should reduce potential
issues caused by inadequate surface preparation, which has been a
factor in past incidents.\15\
---------------------------------------------------------------------------

    \15\ National Transportation Safety Board, ``Safety Through
Reliable Fusion Joints,'' SA-047, https://www.ntsb.gov/safety/safety-alerts/Documents/SA_047.pdf, June 2015.
---------------------------------------------------------------------------

    PHMSA also proposes to clarify Sec.  192.285 in response to
questions PHMSA has received following publication of the rule. First,
PHMSA proposes to remove references to testing in relation to ASTM
F2620 to clarify that only visual inspection in accordance with that
standard is required. A number of stakeholders have asked what specific
testing is required in ASTM F2620. While ASTM F2620 describes testing
in a non-mandatory appendix of the standard, it does not require
specific testing. This change avoids confusion about whether non-
mandatory testing described in ASTM F2620 is required. PHMSA also
proposes to clarify that testing in accordance with Sec.  192.283(a) is
still required for PE heat fusion joints. Especially with the proposed
deletion of references to ASTM F2620 testing, the current text could be
read to require only visual inspection in accordance with ASTM F2620
for PE heat fusion joints. These changes clarify PHMSA's intent to
require that such joints be tested in accordance with Sec.  192.283(a)
and visually inspected in accordance with ASTM F2620 (or an equivalent
or superior procedure).
    In addition to the matters raised above, PHMSA issues correcting
amendments to address the following:

Design Pressure for Plastic Pipe

    In Sec.  192.121(a), the words ``design formula'' are replaced with
the words ``design pressure,'' which is more accurate.
Minimum Wall Thickness for 1'' CTS Pipe
    In the minimum wall thickness tables for polyethylene (Sec.
192.121(c)(2)(iv)), polyamide 11 (PA-11) (Sec.  192.121(d)(2)(iv)), and
polyamide 12 (PA-12) (Sec.  192.121(e)(4)), the minimum wall thickness
for standard dimension ratio (SDR) 11, 1'' copper tubing size (CTS)
pipe is corrected to be 0.101 inches rather than 0.119 inches. The
former, 0.101 inches, is the correct minimum wall thickness for SDR 11,
1'' CTS pipe in ASTM D2513, ASTM F2945, and ASTM F2785.
Qualifying Joining Procedures
    In Sec.  192.283(a)(3), ``no more than 25% elongation'' is
corrected to read ``no less than 25% elongation.'' PHMSA is also
proposing to clarify that the test required by this section is a
tensile test. The language in the code prior to the plastic pipe rule
required tensile testing and the elongation performance metric is a
tensile testing metric. However, with other revisions to Sec.
192.283(a)(3) in the plastic rule, the word tensile was inadvertently
removed.
Dates
    In Sec.  192.121(c)(2) and (2), PHMSA clarifies that PE pipe and
PA-12 pipe respectively produced on January 22, 2019 may also use a DF
of 0.40 rather than 0.32, subject to applicable restrictions in those
paragraphs.
Corrections to 192.7
    PHMSA also proposes editorial amendments to Sec.  192.7(a) to meet
requirements from the Office of the Federal Register and a revision to
update the address for API.

H. Test Factors for Pressure Vessels (Section 192.153)

    On March 11, 2015, PHMSA published a final rule (80 FR 12762) that,
among other changes, added Sec.  192.153(e). Section 192.153(e)
clarified that pressure vessels subject to Sec.  192.505(b) must be
tested to at least the test factor required by that section--1.5 times
the maximum allowable operating pressure (MAOP). On April 10, 2015,
INGAA submitted a petition for reconsideration concerning the revision,
arguing that PHMSA lacked technical justification for a 1.5 times MAOP
test factor versus the 1.3 times MAOP test factor permitted in the
American Society of Mechanical Engineers Boiler and Pressure Vessel
Code (ASME BPVC).
    PHMSA commissioned a report by the Oak Ridge National Laboratories
on the technical equivalency between the 1992 and 2015 editions of the
ASME BPVC. One of the changes between these two editions was the test
factor. The 1992 edition of the ASME BPVC has a 1.5 times MAOP test
factor, while the 2001 edition and all subsequent editions have a 1.3
times MAOP test factor. That study found that pressure vessels that are
designed, fabricated, and tested in

accordance with the provisions specified in the 2015 edition of ASME
BPVC and are subjected to a hydrostatic test pressure equal to 1.3 MAOP
are equivalent in safety to pressure vessels that are designed and
fabricated in accordance with the 1992 edition of the standard and
subjected to a hydrostatic pressure equal to 1.5 MAOP. A copy of this
report is available in the docket.\16\
---------------------------------------------------------------------------

    \16\ ORNL/TM-2017/66.
---------------------------------------------------------------------------

    PHMSA is therefore proposing to revise the test requirements for
the pressure vessels described in paragraphs (a) and (b) of Sec.
192.153, ``Components fabricated by welding.'' First, consistent with
the 2007 edition of the ASME BPVC,\17\ PHMSA is proposing a test factor
of 1.3 times the MAOP for pressure vessels installed since July 14,
2004.\18\ The test requirements for pressure vessels under the
alternative MAOP requirements at Sec.  192.620 remain unchanged. PHMSA
is proposing to apply a test pressure factor of 1.3 times MAOP to
pressure vessels installed between July 14, 2004, and the effective
date of this rule once finalized. Consistent with the revised test
pressure factor, PHMSA proposes to exempt pressure vessels installed
after July 14, 2004, from the testing requirements at Sec. Sec.
192.505(b) and 192.619(a)(2) and from the pressure test duration
requirements in subpart J. Pressure vessels that were properly designed
and tested in accordance with the ASME BPVC since 2004 would be in
compliance with the revised PSR, provided they were tested to at least
1.3 times MAOP.
---------------------------------------------------------------------------

    \17\ Currently incorporated by reference (see Sec.  192.7).
    \18\ The 2001 edition of the ASME BPVC was the first to allow a
1.3 test factor. PHMSA incorporated by reference that edition into
part 192 in June 2004, effective July 14, 2004. All subsequent
editions of the ASME BPVC also include a 1.3 test factor. Pressure
vessels that were properly designed and tested in accordance with
the ASME BPVC since 2004 would be in compliance with the revised
PSR, provided they were tested to at least 1.3 times MAOP.
---------------------------------------------------------------------------

    Pressure vessels that are new, replaced, or relocated after the
effective date of the rule would need to be tested for the duration
required in subpart J for the pipeline to which it is being added.
Vessels installed within a pipeline being operated at a hoop stress of
30 percent or more must be tested for either 4 or 8 hours (Sec.
192.505), vessels installed within a pipeline being operated at a hoop
stress less than 30 percent must be tested for at least 1 hour (Sec.
192.507), and pressure vessels installed within a pipeline being
operated at a pressure below 100 psi must be tested for a duration that
ensures the discovery of all potentially hazardous leaks (Sec.
192.509). These are the same, long-standing test duration requirements
that currently apply for every other component on a pipeline facility.
    For newly manufactured pressure vessels installed after the
effective date of the rule, PHMSA proposes to accept pre-installation
and manufacturer tests with certain conditions and clarify that the
pressure test duration requirements in subpart J apply. PHMSA proposes
to accept a pressure test done by the manufacturer in accordance with
Sec.  192.153 and the ASME BPVC, provided that the operator conducts
and documents an inspection certifying that the pressure vessel has not
been damaged during transport. If the pressure vessel has been damaged,
it would have to be remediated consistent with the ASME BPVC. A
pressure vessel that has been used for any purpose prior to
installation on a pipeline facility must be pressure tested again in
place, consistent with the existing requirement at Sec.  192.503(a).

Welder Requalification

I. Requalification Scheduling (Section 192.229)

    PHMSA is proposing to amend Sec.  192.229(b) to streamline
compliance with welder requalification requirements. Currently, welders
may not weld with a welding process if they have not engaged in welding
with that process within the last six months. GPTC submitted a petition
for rulemaking requesting PHMSA allow welders to demonstrate they have
engaged in welding with a welding process at least twice each calendar
year, but at intervals not exceeding 7\1/2\ months, provided the welds
were tested and found acceptable in accordance with API Standard
1104.\19\ API Std 1104 is the primary standard for welding steel piping
and for testing welds on steel pipelines. It covers the requirements
for welding and nondestructive testing of pipeline welds. In part 192,
this standard is used for qualifying welders, welding procedures, and
welding operators, and interpreting the results of non-destructive
tests. The current requirement does not match other welder
requalification requirements that use the flexible calendar year
format, and operators must therefore either maintain alternative
recordkeeping procedures for this requirement or default to 6 months.
---------------------------------------------------------------------------

    \19\ See Docket No. PHMSA-2014-0015.
---------------------------------------------------------------------------

    PHMSA is proposing to revise Sec.  192.229(b) to specify that
welders or welding operators may not weld with a particular welding
process unless they have engaged in welding with that process within
the preceding 7\1/2\ months and the welds were tested and found
acceptable in accordance with API 1104. This change provides operators
some flexibility in scheduling welding activities to maintain welder
requalification. The proposed revision to Sec.  192.229(b) is also more
consistent with Sec.  192.229(d)(2). This is potentially beneficial for
welders who weld relatively infrequently. The requirements in Sec.
192.229(b) currently must be completed within the previous 6 months, so
a welder who wants to use the same two welds to meet the requirements
of both Sec.  192.229(d)(2) and Sec.  192.229(b) currently must perform
both welds within 6 months, despite Sec.  192.229(d)(2) allowing for an
interval of up to 7\1/2\ months. The proposed revisions allow such
welders to benefit from the flexible language in Sec.  192.229(d)(2).
PHMSA does not anticipate a decrease in safety, as a 7\1/2\-month
interval is already permitted for requalification under Sec.
192.229(d)(2)(i), and the change will only affect welders who are not
welding throughout the year.

Pre-Test Applicability

J. Pre-Testing Fabricated Assemblies and Short Segments of Pipe
(Section 192.507)

    Section 192.505(d) permits operators to test fabricated units and
short segments of pipe prior to installation on steel pipelines
operated at a hoop stress greater than 30 percent or more of SMYS if a
post-installation test is not practicable. PHMSA is proposing to add a
new paragraph (d) to Sec.  192.507 to extend this allowance to steel
pipelines operated at a hoop stress less than 30 percent of SMYS and at
or above 100 psi.
    Section 192.505 outlines strength testing requirements for steel
pipelines operating at a hoop stress greater than 30 percent of SMYS.
One of the strength testing requirements at Sec.  192.505(d) permits
the use of a pre-installation or factory pressure test for fabricated
units and short sections of pipe where a post-installation test is not
feasible. GPTC petitioned PHMSA to move this provision to the general
test requirements in Sec.  192.503. This would permit operators to use
pre-tested pipe and fabricated units in applications outside of higher
stress transmission pipelines. As this provision is currently
applicable to higher-stress pipelines operating at a hoop stress
greater than 30 percent of SMYS only, extending the broader pre-testing
provision to lower-stress pipelines would not increase

pipeline safety risks. This proposed change will provide greater
flexibility and efficiency for operators of lower-stress pipelines,
especially during maintenance activities.
    Typically, a post-installation test is practicable for new
construction, but may be impracticable for repairs. For example, to
complete a pressure (post-installation) test on a short segment of pipe
used as a repair, the area being tested must be isolated from the rest
of the line. For a pressure test of a short replacement pipe segment,
operators would either weld caps on the segment and test it alongside
the pipe in or near the trench, or install the segment and install caps
to isolate the segment elsewhere along the line. The former is no
different than a ``pre-installation'' test except that it occurs within
the pipeline right of way. The latter requires cutting out additional
pipe segments to install the caps necessary to isolate the test
segment. Depending on the test procedure, these caps would then be
replaced with pre-tested pipe anyway. A pre-installation test in this
scenario provides an equivalent or superior level of safety with
potentially lower costs.
    Instead of adding pre-testing provisions to the general
requirements at Sec.  192.503, PHMSA proposes to add Sec.  192.507(d)
to permit pre-testing on steel pipelines operating at a hoop stress
less than 30 percent of SMYS at or above 100 psi. This does not extend
pre-testing provisions to pipelines operating below 100 psi (Sec.
192.509), service lines (Sec.  192.511), or plastic pipelines (Sec.
192.513). Individual components, excluding short segments of pipe, may
still be installed on those facilities with a pre-installation test
pursuant to Sec.  192.503(e). PHMSA will continue to evaluate this
issue and encourages interested parties to submit comments on whether
it is appropriate to extend pre-testing provisions to such facilities,
propose requirements that should apply if pre-testing provisions are
extended to such facilities, and provide any relevant information on
safety or cost impacts.

V. Availability of Standards Incorporated by Reference

    PHMSA currently incorporates by reference into 49 CFR parts 192,
193, and 195 all or parts of more than 60 standards and specifications
developed and published by standard development organizations (SDO). In
general, SDOs update and revise their published standards every 2 to 5
years to reflect modern technology and best technical practices. ASTM
International (ASTM) often updates some of its more widely used
standards every year. Sometimes multiple editions are published in a
given year.
    The National Technology Transfer and Advancement Act of 1995
(NTTAA), Public Law 104-113, directs federal agencies to use standards
developed by voluntary consensus standards bodies in lieu of
government-written standards whenever possible. Voluntary consensus
standards bodies develop, establish, or coordinate technical standards
using agreed-upon procedures. In addition, OMB issued Circular A-119 to
implement section 12(d) of the NTTAA relative to the utilization of
consensus technical standards by federal agencies. This circular
provides guidance for agencies participating in voluntary consensus
standards bodies and describes procedures for satisfying the reporting
requirements in the NTTAA.
    Accordingly, PHMSA has the responsibility for determining, via
petitions or otherwise, which currently referenced standards should be
updated, revised, or removed, and which standards should be added to
the PSR. Revisions to materials incorporated by reference in the PSR
are handled via the rulemaking process, which allows for the public and
regulated entities to provide input. During the rulemaking process,
PHMSA must also obtain approval from the Office of the Federal Register
to incorporate by reference any new materials.
    Pursuant to 49 U.S.C. 60102(p), PHMSA may not issue a regulation
that incorporates by reference any documents or portions thereof unless
the documents or portions thereof are made available to the public,
free of charge.
    Further, the Office of the Federal Register issued a rulemaking on
November 7, 2014, that revised 1 CFR 51.5 to require that agencies
detail in the preamble of an NPRM the ways the materials it proposes to
incorporate by reference are reasonably available to interested
parties, or how the agency worked to make those materials reasonably
available to interested parties (79 FR 66278).
    To meet its statutory obligation for this rulemaking, PHMSA
negotiated agreements with API and ASTM to provide viewable copies of
standards incorporated by reference in the pipeline safety regulations
available to the public at no cost. API Std 1104 is available at
https://www.api.org/products-and-services/standards/rights-and-usage-policy#tab-ibr-reading-room. The ASTM standards are available at
https://www.astm.org/READINGLIBRARY/. In addition, PHMSA will provide
individual members of the public temporary access to any standard that
is incorporated by reference. Requests for access can be sent to the
following email address<EMAIL_ADDRESS>
VI. Regulatory Analyses and Notices

A. Legal Authority for This Rulemaking

    This proposed rule is published under the authority of the federal
pipeline safety statutes (49 U.S.C. 60101 et seq.). Section 60102(a)
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) of
the federal pipeline safety statutes states that the Secretary shall,
to the extent appropriate and practicable, update incorporated industry
standards that have been adopted as a part of the pipeline safety
regulations. The Secretary has delegated the authority in section 60102
to the Administrator of PHMSA (49 CFR 1.97).

B. Executive Order 12866 and DOT Regulatory Policies and Procedures

    E.O. 12866, ``Regulatory Planning and Review'' (58 FR 51735; Oct.
4, 1993), and DOT regulations governing rulemaking procedures (49 CFR
part 5) require that PHMSA submit ``significant regulatory actions'' to
the OMB for review. This NPRM is a significant regulatory action under
section 3(f) of E.O. 12866 and under DOT and was therefore reviewed by
OMB.
    PHMSA anticipates that, if promulgated, this NPRM would have
economic benefits to the public and the regulated community by reducing
unnecessary cost burdens without increasing risks to public safety or
the environment. PHMSA estimates that the proposed rule will result in
annualized cost savings of approximately $129 million per year, based
on a 7 percent discount rate. Nearly all of the quantified cost savings
in the proposed rule are from the proposed revisions to farm tap
requirements and the revised atmospheric corrosion reassessment
interval for distribution service lines. In support of this NPRM, PHMSA
prepared a Preliminary RIA with estimated costs and benefits. A copy of
the Preliminary RIA is available in the public docket.

C. Executive Order 13771

    This proposed rule is expected to be an E.O. 13771 deregulatory
action. Details on the estimated cost savings of this proposed rule can
be found in the rule's economic analysis in the RIA.

D. Executive Order 13132--``Federalism''

    E.O. 13132 (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 have the ability to augment pipeline safety requirements for
intrastate pipelines regulated by PHMSA but may not approve safety
requirements less stringent than those required by federal law. A state
may also regulate an intrastate pipeline facility PHMSA does not
regulate. 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.

E. Executive Order 13175--``Consultation and Coordination With Indian
Tribal Governments''

    E.O. 13175 (65 FR 67249; Nov. 6, 2000) requires agencies to
consider and consult with Tribal governments when formulating policies.
PHMSA does not anticipate that this NPRM will significantly or uniquely
affect Tribal governments or impose substantial direct compliance
costs; as such, the funding and consultation requirements of E.O. 13175
would not apply. PHMSA invites Tribal communities and governments to
comment on this NPRM.

F. Executive Order 13211--``Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use''

    E.O. 13211 (66 FR 28355; May 22, 2001) requires agencies to submit
``significant energy actions'' to OMB for review. This NPRM is not a
``significant energy action'' under E.O. 13211 because it is unlikely
to have a significant adverse effect on the supply, distribution, or
use of energy. Therefore, no additional analysis is necessary under
E.O. 13211.

G. Executive Order 13272--``Regulatory Flexibility Act''

    The Regulatory Flexibility Act of 1980 (5 U.S.C. 601 et seq.), as
amended, requires federal agencies to prepare an initial regulatory
flexibility analysis describing impacts on small entities whenever an
agency is required by 5 U.S.C. 553 to publish a general notice of
proposed rulemaking for any proposed rulemaking. PHMSA determined that
the cost-savings in the proposed rule may result in significant
economic impacts on a substantial number of small entities. An analysis
of the potential economic impacts of the proposed rule on small
entities is included in the RIA, which is available for public review
and comment in the docket for this rulemaking.

H. Paperwork Reduction Act of 1995

    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. PHMSA estimates that the
proposals in this rulemaking will impact the information collections
described below.
    Based on the proposals in this rule, PHMSA will submit an
information collection revision request to OMB for approval based on
the requirements in this proposed rule. The following information is
provided for each information collection: (1) Title of the information
collection; (2) OMB control number; (3) Current expiration date; (4)
Type of request; (5) Abstract of the information collection activity;
(6) Description of affected public; (7) Estimate of total annual
reporting and recordkeeping burden; and (8) Frequency of collection.
The information collection burden for the following information
collections are estimated to be revised as follows:
    1. Title: Incident and Annual Reports for Gas Pipeline Operators.
    OMB Control Number: 2137-0635.
    Current Expiration Date: 01/31/2023.
    Abstract: This information collection covers the collection of
information from Gas pipeline operators for Incident reporting. PHMSA
estimates that due to the revised monetary damage threshold for
reporting incidents operators will submit 26 fewer gas distribution
incident reports, and 13 fewer gas transmission reports. Operators
currently spend 12 hours completing each incident report. Therefore,
PHMSA expects to eliminate 39 responses and 468 hours from this
information collection as a result of the provisions in the proposed
rule. PHMSA is also revising PHMSA F 7100.1, the Gas Distribution
Incident Report, to collect data on mechanical joint failures that
arise to the level of an incident as stipulated in 49 CFR 191.3. PHMSA
does not expect operators to incur additional burden due to this
change.
    Affected Public: All gas pipeline operators.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 262.
    Total Annual Burden Hours: 3,144.
    Frequency of Collection: On Occasion.
    2. Title: Incident and Annual Reports for Gas Pipeline Operators.
    OMB Control Number: 2137-0522.
    Current Expiration Date: 01/31/2023.
    Abstract: This information collection covers the collection of
information from Gas pipeline operators for immediate notice of
incidents and Annual reports. Based on the proposals in this rule,
PHMSA plans to eliminate the Mechanical Fitting Failure report form
under this OMB Control Number and have operators submit the annual
total of mechanical joint failures on the Gas Distribution Annual
Report under OMB Control Number 2137-0629. PHMSA estimates that it
currently receives, on average, 8,300 Mechanical Fitting Failure
Reports each year with each operator spending, on average, 1 hour to
complete each report. By eliminating this report, PHMSA plans to reduce
the burden for this information collection by 8,300 responses and 8,
300 burden hours.
    Affected Public: All gas pipeline operators.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 2,247.
    Total Annual Burden Hours: 71,801.
    Frequency of Collection: Regular.
    3. Title: Pipeline Safety: Integrity Management Program for Gas
Distribution Pipelines.
    OMB Control Number: 2137-0625.
    Current Expiration Date: 06/30/2022.
    Abstract: The Federal Pipeline Safety Regulations require operators
of gas distribution pipelines to develop and implement IM programs.
    PHMSA proposes to eliminate this requirement for master meter
operators. PHMSA estimates that, on average, 5,461 master meter
operators spend 26 hours, annually, developing new IM plans and/or
updating their existing IM plans. Eliminating this requirement for
master meter operators will eliminate recordkeeping burdens for these
5,461 existing master meter operators, saving 141, 986 hours of burden
annually.
    Affected Public: Natural Gas Pipeline Operators.

    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 3,882.
    Total Annual Burden Hours: 723,192.
    Frequency of Collection: On occasion.
    4. Title: Gas Distribution Annual Report.
    OMB Control Number: 2137-0629.
    Current Expiration Date: 10/31/2021.
    Abstract: The Federal Pipeline Safety Regulations require
distribution operators to prepare and submit annual reports with
summary information on their pipeline infrastructure. PHMSA proposes to
shift the mechanical fitting failure form requirements to a count of
mechanical fitting failures on the distribution annual report form.
PHMSA estimates that it will take operators approximately 25 minutes
(.42 hours) to add this information to the annual report. As a result,
the burden for this information collection will increase by
approximately 607 hours. This addition will have no effect on the total
number of reports submitted.
    Affected Public: Natural Gas Distribution Pipeline Operators.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 1,446.
    Total Annual Burden Hours: 25,189.
    Frequency of Collection: Annually.

I. Unfunded Mandates Reform Act of 1995

    The Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1501 et seq.)
requires federal agencies to assess the effects of federal regulatory
actions on state, local, and tribal governments, and the private
sector.\20\ For any NPRM that includes a federal mandate that may
result in the expenditure by state, local, and Tribal governments, in
the aggregate of $100 million or more in any given year, the agency
must prepare, amongst other things, a written statement that
qualitatively and quantitatively assesses the costs and benefits of the
federal mandate.\21\ A federal mandate is defined, in part, as a
regulation that imposes an enforceable duty upon state, local, or
Tribal governments or would reduce or eliminate the amount of
authorization of appropriation for federal financial assistance that
would be provided to state, local, or Tribal governments for the
purpose of complying with a previous federal mandate.\22\ 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.
---------------------------------------------------------------------------

    \20\ 2 U.S.C. 1531.
    \21\ Id. 1532.
    \22\ Id. Sec. Sec.  658(5)(A), 1555.
---------------------------------------------------------------------------

J. 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, NEPA
implementing regulations (40 CFR parts 1500-1508), and DOT Order
5610.1C. PHMSA has prepared a preliminary environmental assessment (EA)
and 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.

K. Regulation Identifier Number (RIN)

    A regulation identifier number (RIN) is assigned to each regulatory
action listed in the Unified Agenda of Federal Regulations. The
Regulatory Information Service Center publishes the Unified Agenda in
the spring and fall of each year. The RIN number contained in the
heading of this document is a cross-reference for this action to the
Unified Agenda.

List of Subjects

Part 191

    Pipeline reporting requirements, Integrity management, Pipeline
safety, Gas gathering.

Part 192

    Incorporation by reference, Pipeline safety, Fire prevention,
Security measures.

    For the reasons provided in the preamble, PHMSA is proposing to
amend 49 CFR parts 191 and 192 as follows:

PART 191--TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE;
ANNUAL REPORTS, INCIDENT REPORTS, AND SAFETY-RELATED CONDITION
REPORTS

0
1. The authority citation for 49 CFR Part 191 continues to read as
follows:

    Authority: 49 U.S.C. 5121, 60102, 60103, 60104, 60108, 60117,
60118, 60124, 60132, and 60141; and 49 CFR 1.97.

0
2. In Sec.  191.3, in the definition of ``Incident'' revise paragraph
(1)(ii) to read as follows:

Sec.  191.3   Definitions.

* * * * *
    Incident means any of the following events:
    (1) * * *
    (ii) Estimated property damage of $122,000 or more, including loss
to the operator and others, or both, but excluding the cost of gas
lost; or
* * * * *
0
3. In Sec.  191.11, revise paragraph (b) to read as follows:

Sec.  191.11  Distribution system: Annual Report.

* * * * *
    (b) Not required. The annual report requirement in this section
does not apply to a master meter system, a petroleum gas system that
serves fewer than 100 customers from a single source, or an individual
service line directly connected to an unregulated gathering or
production pipeline.

Sec.  191.12  [Removed and reserved].

0
4. Remove and reserve Sec.  191.12.

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

0
5. The authority citation for 49 CFR part 192 continues to read as
follows:

    Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60110,
60113, 60116, 60118, 60137, and 60141; and 49 CFR 1.97.

0
6. In Sec.  192.7:
0
a. Revise paragraph (a), paragraph (b) introductory text, and paragraph
(b)(9);
0
b. Remove and reserve paragraph (c)(7); and
0
c. Revise paragraphs (d)(11) and (20).

    The revisions read as follows:

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

    (a) Certain material is incorporated by reference into this part
with the approval of the Director of the Federal Register under 5
U.S.C. 552(a) and 1 CFR part 51. All approved material is available for
inspection at Office of Pipeline Safety, Pipeline and Hazardous
Materials Safety Administration, 1200 New Jersey Avenue SE, Washington,
DC 20590,<PHONE_NUMBER>, https://www.phmsa.dot.gov/pipeline/regs, and is
available from the sources listed in the remaining paragraphs of this
section. It is also available for inspection at the National Archives
and Records Administration (NARA). For information on the availability
of this material at NARA, email<EMAIL_ADDRESS>or go to
www.archives.gov/federal-register/cfr/ibr-locations.html.
    (b) American Petroleum Institute (API), 200 Massachusetts Ave NW,
Suite 1100, Washington, DC 20001, and

phone:<PHONE_NUMBER>, website: https://www.api.org/.
* * * * *
    (9) API Standard 1104, ``Welding of Pipelines and Related
Facilities,'' 20th edition, October 2005, including errata/addendum
(July 2007) and errata 2 (2008), (API Std 1104), IBR approved for
Sec. Sec.  192.225(a); 192.227(a); 192.229(b); 192.229(c); 192.241(c);
and Item II, Appendix B.
* * * * *
    (d) * * *
    (13) ASTM D2513-18a, ``Standard Specification for Polyethylene (PE)
Gas Pressure Pipe, Tubing, and Fittings,'' approved August 1, 2018,
(ASTM D2513), IBR approved for Item I, Appendix B to Part 192.
* * * * *
    (20) ASTM F2620-19, ``Standard Practice for Heat Fusion Joining of
Polyethylene Pipe and Fittings,'' Feb. 1, 2019, (ASTM F2620), IBR
approved for Sec. Sec.  192.281(c) and 192.285(b)(2)(i).
0
7. In Sec.  192.121:
0
a. In the first sentence of paragraph (a), remove the words ``Design
formula. Design formulas for plastic pipe are'' and add in their place
the words ``Design pressure. The design pressure for plastic pipe is'';
0
b. In paragraph (c)(2) introductory text add the words ``on or'' after
the word ``produced'';
0
c. Revise paragraphs (c)(2)(iii), (c)(2)(iv), and (d)(2)(iv);
0
d. In paragraph (e) introductory text add the words ``on or'' after the
word ``produced''; and

    (5) Revise paragraph (e)(4).
    The revisions read as follows:

Sec.  192.121   Design of plastic pipe.

    (a) Design pressure. The design pressure for plastic pipe is * * *
* * * * *
    (c) * * *
    (2) * * *
    (iii) The pipe has a nominal size (IPS or CTS) of 24 inches or
less; and
    (iv) The wall thickness for a given outside diameter is not less
than that listed in table 1 to this paragraph (c)(2)(iv).

                     Table 1 to Paragraph (c)(2)(iv)
------------------------------------------------------------------------
             PE pipe: Minimum wall thickness and SDR values
-------------------------------------------------------------------------
                                           Minimum wall
           Pipe size (inches)                thickness     Corresponding
                                             (inches)      SDR (values)
------------------------------------------------------------------------
\1/2\'' CTS.............................           0.090               7
\1/2\'' IPS.............................           0.090             9.3
\3/4\'' CTS.............................           0.090             9.7
\3/4\'' IPS.............................           0.095              11
1'' CTS.................................           0.101              11
1'' IPS.................................           0.119              11
1 \1/4\'' IPS...........................           0.151              11
1 \1/2\'' IPS...........................           0.173              11
2''.....................................           0.216              11
3''.....................................           0.259            13.5
4''.....................................           0.265              17
6''.....................................           0.315              21
8''.....................................           0.411              21
10''....................................           0.512              21
12''....................................           0.607              21
16''....................................           0.762              21
18''....................................           0.857              21
20''....................................           0.952              21
22''....................................           1.048              21
24''....................................           1.143              21
------------------------------------------------------------------------

    (d) * * *
    (2) * * *
    (iv) The minimum wall thickness for a given outside diameter is not
less than that listed in table 2 to paragraph (d)(2)(iv):

                     Table 2 to Paragraph (d)(2)(iv)
------------------------------------------------------------------------
            PA-11 pipe: Minimum wall thickness and SDR values
-------------------------------------------------------------------------
                                           Minimum wall
           Pipe size (inches)                thickness     Corresponding
                                             (inches)      SDR (values)
------------------------------------------------------------------------
\1/2\'' CTS.............................           0.090             7.0
\1/2\'' IPS.............................           0.090             9.3
\3/4\'' CTS.............................           0.090             9.7
\3/4\'' IPS.............................           0.095              11
1'' CTS.................................           0.101              11
1'' IPS.................................           0.119              11
1 \1/4\'' IPS...........................           0.151              11
1 \1/2\'' IPS...........................           0.173              11
2'' IPS.................................           0.216              11
3'' IPS.................................           0.259            13.5
4'' IPS.................................           0.333            13.5
6'' IPS.................................           0.491            13.5
------------------------------------------------------------------------

    (e) * * *
    (4) The minimum wall thickness for a given outside diameter is not
less than that listed in table 3 to paragraph (e)(4).

                       Table 3 to Paragraph (e)(4)
------------------------------------------------------------------------
            PA-12 pipe: Minimum wall thickness and SDR values
-------------------------------------------------------------------------
                                           Minimum wall
           Pipe size (inches)                thickness     Corresponding
                                             (inches)      SDR (values)
------------------------------------------------------------------------
\1/2\'' CTS.............................           0.090               7
\1/2\'' IPS.............................           0.090             9.3
\3/4\'' CTS.............................           0.090             9.7
\3/4\'' IPS.............................           0.095              11
1'' CTS.................................           0.101              11
1'' IPS.................................           0.119              11
1 \1/4\'' IPS...........................           0.151              11
1 \1/2\'' IPS...........................           0.173              11
2'' IPS.................................           0.216              11
3'' IPS.................................           0.259            13.5
4'' IPS.................................           0.333            13.5
6'' IPS.................................           0.491            13.5
------------------------------------------------------------------------

* * * * *
0
8. In Sec.  192.153 revise paragraph (b) introductory text and
paragraph (e) to read as follows:

Sec.  192.153   Components fabricated by welding.

* * * * *
    (b) Each prefabricated unit that uses plate and longitudinal seams
must be designed, constructed, and tested in accordance with the ASME
BPVC (Rules for Construction of Pressure Vessels as defined in either
Section VIII Division 1 or Section VIII Division 2; incorporated by
reference, see Sec.  192.7), except for the following:
* * * * *
    (e) The test requirements for pressure vessels, defined for this
paragraph as components with a design pressure established in
accordance with paragraph (a) or paragraph (b) of this section are as
follows.
    (1) Pressure vessels installed after July 14, 2004 are not subject
to the strength testing requirements at Sec. Sec.  192.505(b) and
192.619(a)(2), but must be pressure tested in accordance with paragraph
(a) or paragraph (b) of this section and with a test factor of at least
1.3 times MAOP.
    (2) Pressure vessels must be pressure tested for a duration
specified as follows:
    (i) Pressure vessels installed after July 14, 2004, but before
[Insert the Effective Date of the Rule] are exempt from Sec. Sec.
192.505(c), 192.505(d), and 192.507(c) and must instead be tested for a
duration consistent with the ASME BPVC requirements referenced in
paragraph (a) or (b) of this section.
    (ii) Pressure vessels installed on or after [EFFECTIVE DATE OF
FINAL RULE] must be tested for the duration specified in either Sec.
192.505(c), 192.505(d), 192.507(c), or 192.509(a), whichever is
applicable for the pipeline in which the component is being installed.
    (3) After [EFFECTIVE DATE OF FINAL RULE], if a newly manufactured
pressure vessel is relocated to a pipeline facility after an initial
pressure test by

the manufacturer, the operator must either:
    (i) Pressure test the vessel in-place after it has been transported
in accordance with the requirements of this section; or
    (ii) Inspect the pressure vessel and confirm that the component was
not damaged during transportation and installation into the pipeline.
Inspection records for the component must be kept for the operational
life of the pressure vessel. If the pressure vessel has been damaged,
it must be remediated or retested in accordance with the ASME BPVC
requirements referenced in paragraphs (a) or (b) of this section.
0
9. In Sec.  192.229, revise paragraph (b) to read as follows:

Sec.  192.229   Limitations on welders and welding operators.

* * * * *
    (b) A welder or welding operator may not weld with a particular
welding process unless, within the preceding 6 calendar months, the
welder or welding operator was engaged in welding with that process.
Alternatively, welders or welding operators may demonstrate they have
engaged in a specific welding process if they have performed a weld
with that process that was tested and found acceptable under section 6,
9, 12, or Appendix A of API Std 1104 (incorporated by reference, see
Sec.  192.7) within the preceding 7\1/2\ months.
* * * * *
0
10. In Sec.  192.281, revise paragraph (c) to read as follow:

Sec.  192.281   Plastic Pipe.

* * * * *
    (c) Heat-fusion joints. Each heat fusion joint on a PE pipe or
component, except for electrofusion joints, must comply with ASTM F2620
(incorporated by reference in Sec.  192.7), or an equivalent or
superior written procedure that has been proven by test or experience
to produce strong gastight joints, and the following:
* * * * *
0
11. In Sec.  192.283 revise paragraph (a)(3) to read as follows:

Sec.  192.283  Plastic pipe: Qualifying joining procedures.

    (a) * * *
    (3) For procedures intended for non-lateral pipe connections,
perform tensile testing in accordance with a listed specification. If
the test specimen elongates no less than 25% or failure initiates
outside the joint area, the procedure qualifies for use.
* * * * *
0
12. In Sec.  192.285, revise paragraph (b)(2)(i) to read as follows:

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

* * * * *
    (b) * * *
    (2) * * *
    (i) Tested under any one of the test methods listed under Sec.
192.283(a), and for PE heat fusion joints (except for electrofusion
joints) visually inspected in accordance with ASTM F2620 (incorporated
by reference, see Sec.  192.7), or a written procedure that has been
demonstrated to provide an equivalent or superior level of safety,
applicable to the type of joint and material being tested;
* * * * *
0
13. In Sec.  192.465, revise paragraph (b) to read as follows:

Sec.  192.465   External corrosion control: Monitoring.

* * * * *
    (b) Cathodic protection rectifiers and impressed current power
sources must be periodically inspected as follows:
    (1) Each cathodic protection rectifier or impressed current power
source must be inspected six times each calendar year, but with
intervals not exceeding 2\1/2\ months between inspections, to ensure
adequate amperage and voltage levels needed to provide cathodic
protection are maintained. This may be done either through remote
measurement or through an onsite inspection of the rectifier.
    (2) Each remotely monitored rectifier must be physically inspected
for continued safe and reliable operation whenever cathodic protection
tests are performed pursuant to Sec.  192.465(a).
* * * * *
0
14. In Sec.  192.481, revise paragraph (a) and add paragraph (d) to
read as follows:

Sec.  192.481   Atmospheric corrosion control: Monitoring.

    (a) Each operator must inspect and evaluate each pipeline or
portion of the pipeline that is exposed to the atmosphere for evidence
of atmospheric corrosion, as follows:

------------------------------------------------------------------------
                                                Then the frequency of
              Pipeline type:                       inspection is:
------------------------------------------------------------------------
(1) Onshore other than a Service Line.....  At least once every 3
                                             calendar years, but with
                                             intervals not exceeding 39
                                             months.
(2) Onshore Service Line..................  At least once every 5
                                             calendar years, but with
                                             intervals not exceeding 63
                                             months, except as provided
                                             in paragraph (d) of this
                                             section.
(3) Offshore..............................  At least once each calendar
                                             year, but with intervals
                                             not exceeding 15 months.
------------------------------------------------------------------------

* * * * *
    (d) If atmospheric corrosion is found on a service line during the
most recent inspection, then the next inspection of that pipeline or
portion of pipeline must be within 3 calendar years, with an interval
not exceeding 39 months.
0
15. In Sec.  192.505, revise paragraph (c) to read as follows:

Sec.  192.505   Strength test requirements for steel pipelines to
operate at a hoop stress of 30 percent or more of SMYS.

* * * * *
    (c) Except as provided in paragraph (d) of this section, the
strength test must be conducted by maintaining the pressure at or above
the test pressure for at least 8 hours.
* * * * *
0
16. In Sec.  192.507, add paragraph (d) to read as follows:

Sec.  192.507   Test requirements for pipelines to operate at a hoop
stress less than 30 percent of SMYS and at or above 100 p.s.i. (689
kPa) gage.

* * * * *
    (d) For fabricated units and short sections of pipe, for which a
post installation test is impractical, a pre-installation hydrostatic
pressure test must be conducted in accordance with the requirements of
this section.
0
17. In section 192.740, revise the section heading, paragraph (a) and
paragraph (c) to read as follows:

Sec.  192.740   Pressure regulating, limiting, and overpressure
protection--Individual service lines directly connected to regulated
gathering or transmission pipelines.

    (a) This section applies, except as provided in paragraph (c) of
this section, to any service line directly connected to a transmission
pipeline or regulated gathering pipeline that is not operated as part
of a distribution system.
* * * * *
    (c) This section does not apply to equipment installed on:
    (1) Service lines that only serve engines that power irrigation
pumps;
    (2) Service lines included in a distribution integrity management
plan meeting the requirements of subpart P of this part;
    (3) Service lines directly connected to unregulated gathering or
production pipelines; and
    (4) Pipe segments upstream of either: The inlet to the first
pressure regulator,

the connection to customer-owned piping, or the outlet of the meter,
whichever is further upstream.
0
18. Revise section 192.1003 to read as follows:

Sec.  192.1003   What do the regulations in this subpart cover?

    (a) General. Unless exempted in paragraph (b) of this section, this
subpart prescribes minimum requirements for an IM program for any gas
distribution pipeline covered under this part, including liquefied
petroleum gas systems. A gas distribution operator must follow the
requirements in this subpart.
    (b) Exceptions. This subpart does not apply to:
    (1) Individual service lines directly connected to a production or
unregulated gathering pipeline;
    (2) Individual service lines directly connected to either a
transmission or regulated gathering pipeline and maintained in
accordance with Sec.  192.740(a) and (b); and
    (3) Master meter systems.
0
19. In Sec.  192.1005, revise the section heading to read as follows:

Sec.  192.1005   What must a gas distribution operator (other than a
small LPG operator) do to implement this subpart?

* * * * *
0
20. In Sec.  192.1007, revise paragraph (b) to read as follows:

Sec.  192.1007  What are the required elements of an integrity
management plan?

* * * * *
    (b) Identify threats. The operator must consider the following
categories of threats to each gas distribution pipeline: Corrosion
(including atmospheric corrosion), natural forces, excavation damage,
other outside force damage, material or welds, equipment failure,
incorrect operations, and other issues that could threaten the
integrity of its pipeline. An operator must consider reasonably
available information to identify existing and potential threats.
Sources of data may include incident and leak history, corrosion
control records (including atmospheric corrosion records), continuing
surveillance records, patrolling records, maintenance history, and
excavation damage experience.
* * * * *

Sec.  192.1009   [Removed and Reserved]

0
21. Remove and reserve Sec.  192.1009.
0
22. In Sec.  192.1015, revise the section heading, paragraph (a), and
paragraph (b)(2) to read as follows:

Sec.  192.1015   What must a small LPG operator do to implement this
subpart?

    (a) General. No later than August 2, 2011, a small LPG operator
must develop and implement an IM program that includes a written IM
plan as specified in paragraph (b) of this section. The IM program for
these pipelines should reflect the relative simplicity of these types
of pipelines.
    (b) * * *
    (2) Identify threats. The operator must consider, at minimum, the
following categories of threats (existing and potential): Corrosion
(including atmospheric corrosion), natural forces, excavation damage,
other outside force damage, material or weld failure, equipment
failure, and incorrect operation.
* * * * *
0
23. In Sec.  192, in Appendix B, remove the entry for ASTM D2513-12ae1
and add a new entry for ASTM D2513 in alphabetical order to read as
follows:

Appendix B to Part 192--Qualification of Pipe

I. Listed Pipe Specifications

* * * * *
    ASTM D2513--Polyethylene thermoplastic pipe and tubing,
``Standard Specification for Polyethylene (PE) Gas Pressure Pipe,
Tubing, and Fittings,'' (incorporated by reference, see Sec.
192.7).
* * * * *

    Issued in Washington, DC, on May 27, 2020, under authority
delegated in 49 CFR 1.97.
Alan K. Mayberry,
Associate Administrator for Pipeline Safety.

[FR Doc. 2020-11843 Filed 6-8-20; 8:45 am]
 BILLING CODE 4910-60-P