[Federal Register Volume 85, Number 111 (Tuesday, June 9, 2020)]
[Proposed Rules]
[Pages 35240-35254]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[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identify appropriate areas where regulations might be repealed, 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 202-366-0559.

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

[[Page 35241]]

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

[[Page 35242]]

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.

[[Page 35243]]

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

[[Page 35244]]

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

[[Page 35245]]

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

[[Page 35246]]

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

[[Page 35247]]

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

[[Page 35248]]

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

[[Page 35249]]

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 protected].

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.

[[Page 35250]]

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.

[[Page 35251]]

    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, 202-366-4046, 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 protected] 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

[[Page 35252]]

phone: 202-682-8000, 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

[[Page 35253]]

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,

[[Page 35254]]

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