Pipeline Safety: Gas Pipeline Regulatory Reform, 2210-2242 [2021-00208]
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DEPARTMENT OF TRANSPORTATION
Pipeline and Hazardous Materials
Safety Administration
I. Executive Summary
49 CFR Parts 191 and 192
[Docket No. PHMSA–2018–0046; Amdt Nos.
191–29; 192–128]
RIN 2137–AF36
Pipeline Safety: Gas Pipeline
Regulatory Reform
Pipeline and Hazardous
Materials Safety Administration
(PHMSA), DOT.
ACTION: Final rule; withdrawal of
enforcement discretion.
AGENCY:
PHMSA is amending the
Federal Pipeline Safety Regulations to
ease regulatory burdens on the
construction, maintenance, and
operation of gas transmission,
distribution, and gathering pipeline
systems without adversely affecting
safety. The amendments in this rule are
based on rulemaking petitions from
stakeholders, and DOT and PHMSA
initiatives to identify appropriate areas
where regulations might be repealed,
replaced, or modified, and PHMSA’s
review of public comments. PHMSA
also, as of the effective date of this final
rule, withdraws the March 29, 2019
‘‘Exercise of Enforcement Discretion
Regarding Farm Taps’’ and the
unpublished October 27, 2015 letter to
the Interstate Natural Gas Association of
America announcing a stay of
enforcement pertaining to certain
pressure vessels.
DATES: Effective Date: This rule is
effective March 12, 2021.
Incorporation by reference date: The
incorporation by reference of certain
publications listed in the rule is
approved by the Director of the Federal
Register as of March 12, 2021.
Voluntary compliance date: March 12,
2021.
Delayed compliance date:
Compliance with the amendments
adopted in the rule is required
beginning October 1, 2021.
Enforcement discretion withdrawal
date: The withdrawal of 84 FR 11253
(Mar. 26, 2019) is effective as of March
12, 2021.
FOR FURTHER INFORMATION CONTACT:
Sayler Palabrica, Transportation
Specialist, by telephone at 202–366–
0559.
SUPPLEMENTARY INFORMATION:
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SUMMARY:
I. Executive Summary
II. Background
III. Analysis of Comments, GPAC
Recommendations, and PHMSA’s
Response
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IV. Availability of Standards Incorporated by
Reference
V. Regulatory Analyses and Notices
A. Purpose of This Deregulatory Action
PHMSA is amending the Federal
Pipeline Safety Regulations (PSR) at 49
CFR parts 191 and 192 to ease
regulatory burdens on the construction,
operation, and maintenance of gas
transmission, distribution, and
gathering pipeline systems without
adversely affecting safety. These
amendments include regulatory relief
actions identified by internal agency
review, petitions for rulemaking, and
public comments submitted in response
to a Department of Transportation
(DOT) regulatory reform notice entitled
‘‘Notification of Regulatory Review.’’ 1
On June 9, 2020, PHMSA published a
notice of proposed rulemaking (NPRM)
to seek public comments on proposed
changes to the PSR.2 A summary of
those proposed changes, and PHMSA’s
response to stakeholder feedback on the
individual provisions, is provided
below in section III (Analysis of
Comments, GPAC Recommendations,
and PHMSA’s Response).
B. Summary of PSR Amendments
The final rule makes the following
amendments to 49 CFR parts 191 and
192:
A. Revision of certain requirements
(at §§ 191.11, 192.740, and 192.1003)
pertaining to farm taps giving operators
the choice of managing inspections of
pressure regulators serving farm taps
under either their distribution integrity
management plan (DIMP) or by
following the inspection requirements at
§ 192.740;
B. Revision of certain requirements (at
§§ 192.1003, 192.1005 and 192.1015)
pertaining to master meter systems to
exempt operators of these simple
pipeline facilities from DIMP
requirements that had been designed
with complex distribution systems in
mind;
C. Revision of certain reporting
requirements (at §§ 191.12 and
192.1009) to eliminate a dedicated
report form for mechanical fitting
failures (MFFs), and modify other
required report forms to incorporate
more information on MFFs;
D. Revision of the monetary threshold
for incident reporting (at § 191.3) to
update for inflation over the three
decades since the current monetary
threshold was established, and
introduce a new appendix A to part 191
1 82
2 85
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FR 35240.
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to provide for annual updates to that
threshold to account for inflation;
E. Revision of § 192.465 to clarify that
operators may remotely inspect rectifier
stations for external corrosion;
F. Revision of atmospheric corrosion
monitoring requirements (at §§ 192.481,
192.491, 192.1007, and 192.1015) both
to align the inspection interval for
atmospheric corrosion on gas
distribution service pipelines with
leakage survey requirements at
§ 192.723, and to clarify that
consideration of corrosion risks under
DIMP explicitly includes atmospheric
corrosion;
G. Revision of requirements governing
plastic pipe (at §§ 192.7, 192.121,
192.281, 192.285, and appendix B to
part 192) to improve alignment with,
and incorporate by reference, certain
updated industry standards;
H. Revision of test requirements for
pressure vessels at § 192.153 to align
pressure test factor requirements with
industry standards, and to clarify
certain other pressure testing
requirements;
I. Revision of the welding process
requirement at § 192.229 to align better
with welder requalification requirement
at § 192.229(d)(2); and
J. Revision of language at § 192.507 to
extend an existing authorization for pretesting of fabricated units and short
segments of steel pipe prior to
installation on pipelines with highstress operating conditions to pipelines
operating at lower-stress operating
conditions.
C. Costs and Benefits
In accordance with 49 U.S.C. 60102,
Executive Order (E.O.) 12866,3 and DOT
regulations at § 5.13(e), PHMSA has
prepared an assessment of the costs and
benefits of this final rule as well as
reasonable alternatives. The
amendments promulgated in this final
rule are deregulatory, with the intention
and effect of reducing regulatory
burdens, increasing flexibility,
improving efficiency, and adding clarity
to existing rules without adversely
affecting safety. PHMSA expects the
incremental cost savings to accrue on an
ongoing annual basis. PHMSA used a
20-year analysis period for this final
rule. PHMSA estimates the total
quantified annualized cost savings to be
approximately $129.8 million (at a
discount rate of 7 percent) or
approximately $132.5 million (at a
discount rate of 3 percent). Table-1
presents the estimated total cost savings
for the 20-year period and the estimated
3 ‘‘Regulatory Planning and Review,’’ 58 FR 51735
(Oct. 4, 1993).
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annualized cost savings over the same
period.
TABLE 1—TOTAL ESTIMATED DISCOUNTED COST SAVINGS
[2019 $ in millions]
Estimated cost
savings
Category
Total (20 years; discounted at 7 percent) .......................................................................................................................................
Total (20 years; discounted at 3 percent ........................................................................................................................................
Annualized (discounted at 7 percent) ..............................................................................................................................................
Annualized (discounted at 3 percent) ..............................................................................................................................................
PHMSA does not anticipate that the
amendments will have an adverse
impact on safety or a significant effect
on the environment. The largest
quantified cost savings are due to the
PSR amendments related to farm taps
and atmospheric corrosion discussed in
sections III.A and III.F, respectively, of
the preamble to this final rule. PHMSA
expects other amendments to improve
regulatory flexibility, clarity, and
simplicity. Additional details regarding
PHMSA’s evaluation of the costs and
benefits of this final rule are available in
the Final Regulatory Impact Analysis
(RIA) posted in the rulemaking docket.
II. Background
A. Regulatory Reform Executive Orders
and Department Response
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As explained at greater length in the
NPRM,4 DOT published a notice,
‘‘Notification of Regulatory Review,’’ on
October 2, 2017,5 requesting
recommendations on existing DOT rules
and other agency actions that could be
eliminated without adversely affecting
safety. DOT in particular solicited the
public’s assistance in identifying DOT
regulations and other actions which
eliminate jobs or inhibit job creation; are
outdated, unnecessary, or ineffective;
impose costs that exceed benefits; create
a serious inconsistency or otherwise
interfere with regulatory reform
initiatives and policies; could be revised
to use performance standards in lieu of
design standards; or that potentially
unnecessarily encumber energy
production. After a 30-day comment
period, DOT re-opened the comment
period until December 1, 2017.6 DOT
received nearly 3,000 public comments.
Approximately 30 pertained to the
PSR.7
4 85
FR 35241–42.
FR 45750.
6 82 FR 51178.
7 Docket No. DOT–OST–2017–0069.
B. PHMSA Notice of Proposed
Rulemaking
Consistent with DOT’s regulatory
reform efforts and informed by PSRpertinent comments received in
response to the DOT Notification of
Regulatory Review discussed above,
PHMSA’s Office of Pipeline Safety
(OPS) reviewed the PSR and identified
unnecessary, outdated, and non-costjustified regulatory requirements that
could be repealed, replaced, or modified
without adversely affecting safety.
PHMSA also considered certain
petitions for rulemaking and petitions
for reconsideration of earlier PSR
amendments.
On June 9, 2020, PHMSA published
an NPRM 8 proposing several
amendments to 49 CFR parts 191 and
192 to reduce regulatory burdens on
operators of gas pipelines without
adversely affecting safety. The comment
period for the NPRM ended on August
10, 2020. PHMSA received 46
comments on the NPRM, including latefiled comments. PHMSA received
comments from groups representing the
regulated pipeline industry; groups
representing various public interests,
including environmental groups; State
utility commissions and regulators;
individual pipeline operators; and
private citizens. PHMSA received latefiled comments from the National
Association of State Pipeline Safety
Representatives (NAPSR), the Gas
Piping Technology Committee (GPTC), a
coalition of several industry trade
associations, and GPA Midstream.9
PHMSA also had a conversation with a
member of the Gas Pipeline Advisory
Committee (GPAC) and representatives
of the Pipeline Safety Trust (PST) after
the end of the comment period; a
summary of that meeting has been
placed in the rulemaking docket.
Consistent with §§ 5.13(i)(5) and
190.323, PHMSA considered the latefiled comments and materials because of
their relevance to the rulemaking and
the absence of additional expense or
delay resulting from their consideration.
Some of the comments PHMSA
received were beyond the scope of the
amendments proposed in the NPRM.
The issues raised in those comments
may be the subject of other existing or
future rulemaking proceedings.
The remaining comments reflect a
wide variety of views on the merits of
the proposed PSR amendments. PHMSA
read and considered all the comments
posted to the docket for this rulemaking.
These comments and PHMSA’s
response to those comments are
described in section III.
Contemporaneously with PHMSA’s
development of the NPRM, the
President issued E.O. 13924,
‘‘Regulatory Relief to Support Economic
Recovery,’’ 10 directing Federal agencies
to respond to the economic harm caused
by the novel coronavirus by reviewing
their regulations and considering taking
appropriate action, consistent with
applicable law, to temporarily or
permanently rescind or modify those
regulations to reduce regulatory burdens
and thereby promote economic
growth.11 PHMSA understands the cost
savings expected from this final rule to
be consistent with E.O. 13924’s
mandate.
C. Gas Pipeline Advisory Committee
Meeting
The Technical Pipeline Safety
Standards Committee, commonly
known as the Gas Pipeline Advisory
Committee (GPAC; the committee), is an
advisory committee mandated by statute
(49 U.S.C. 60115) that advises PHMSA
on proposed safety standards. The
GPAC is one of two pipeline advisory
committees that focus on technical
safety standards that were established
under the Federal Advisory Committee
Act, as amended (5 U.S.C. App. 1–16).
The GPAC consists of 15 members, with
membership divided among Federal and
State agencies, the natural gas industry,
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FR 35240.
formerly the Gas Processors Association.
9 GPA,
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$1,374.8
1,971
129.8
132.5
10 85
FR 31353 (May 22, 2020).
13924 at § 4.
11 E.O.
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and the public. The GPAC considers the
‘‘technical feasibility, reasonableness,
cost-effectiveness, and practicability’’ of
each proposed pipeline safety standard
and provides PHMSA with
recommended actions pertaining to
those proposals.
The GPAC met in an online virtual
meeting on October 7, 2020 to consider
the regulatory proposals of the NPRM.
The GPAC members discussed
comments made on the NPRM. To assist
the GPAC in its deliberations, PHMSA
presented a description and summary of
the proposals in the NPRM and the
comments received on those issues.
PHMSA also assisted the committee by
fostering discussion, developing
recommendations, and providing
direction on which issues were most
pressing. A transcript of the meeting
and all presented materials is available
in the docket for the rulemaking and on
the web page PHMSA established for
the meeting.12
The committee voted on the technical
feasibility, reasonableness, costeffectiveness, and practicability of each
of the NPRM’s provisions. In many
instances, the committee recommended
changes that the committee found
would make certain proposals more
feasible, reasonable, cost-effective, or
practicable. These balloted
recommendations and the transcript for
the meeting serve as the GPAC’s report
pursuant to 49 U.S.C. 60115. These
recommendations are discussed in
section III of the preamble to this final
rule for each of the topics proposed in
the NPRM.
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III. Analysis of Comments, GPAC
Recommendations, and PHMSA’s
Response
The proposals in the NPRM,
substantive comments received, as well
as the GPAC’s recommendations are
organized by topic below and are
discussed in the appropriate section
with PHMSA’s response to and
resolution of those comments.
Distribution Integrity Management
Program (DIMP)
On December 4, 2009, PHMSA issued
a final rule titled, ‘‘Pipeline Safety:
Integrity Management Program for Gas
Distribution Pipelines.’’ 13 The 2009 rule
created 49 CFR part 192, subpart P,
requiring gas distribution operators to
develop and implement integrity
management (IM) programs. The NPRM
contained two proposed revisions to
DIMP requirements to ease or eliminate
12 https://primis.phmsa.dot.gov/meetings/
MtgHome.mtg?mtg=151&nocache=4862.
13 74 FR 63905.
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regulatory burdens on certain gas
distribution operators. The first revision
is to allow operators of farm taps 14
connected to transmission or regulated
gathering lines the option of managing
maintenance of pressure regulating
devices under either § 192.740 or their
DIMP in accordance with subpart P. As
part of this amendment, PHMSA also
proposed to exempt farm taps
originating from unregulated gathering
and production pipelines from DIMP,
§ 192.740, and incident and annual
reporting requirements in part 191.
Second, the NPRM included a proposal
to revise §§ 192.1003 and 192.1015 to
exempt master meter operators from
DIMP due to their simplicity. Master
meter systems that serve fewer than 100
customers from a single source are
currently required to comply with a
simplified set of DIMP requirements
detailed in § 192.1015.
A. Farm Taps (Sections 191.11, 192.740,
192.1003)
1. PHMSA’s Proposal
In the NPRM, PHMSA proposed to
revise §§ 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 § 192.740.
On January 23, 2017, PHMSA
published a final rule that added
§ 192.740, ‘‘Pressure regulating,
limiting, and overpressure protection—
Individual service lines directly
connected to production, gathering, or
transmission pipelines.’’ 15 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).
Currently, such devices must be
inspected and tested at least once every
3 calendar years, with intervals not to
exceed 39 months. The 2017 rule also
revised the DIMP applicability
regulations at § 192.1003 to exclude
farm taps from DIMP requirements. The
change was intended to create uniform
compliance requirements for farm taps,
address over-pressurization risks, and
decrease the burden of meeting the
14 A ‘‘farm tap’’ is the common name for a
pipeline directly connected to a gas transmission,
production, or gathering pipeline that provides gas
to a customer. The term farm tap is not defined in
the PSR; however, portions of a farm tap upstream
of 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 § 192.3 (definition of ‘‘service
line’’).
15 82 FR 7972.
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DIMP requirements for transmission and
gathering line operators who otherwise
do not operate distribution assets.
However, PHMSA had not considered
that some farm taps are operated by
local distribution companies rather than
the operator of the transmission,
gathering or production line itself.
Operators who historically had included
farm taps in their DIMP found it
burdensome to remove those facilities
from their plan and reevaluate the risks
under a new, prescriptive program.
DOT received a comment in response
to the Notification of Regulatory Review
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
§§ 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, the NPRM
proposed to revise §§ 192.740 and
192.1003 to exempt farm taps
originating from transmission lines and
regulated gathering lines from § 192.740
if they are included in a DIMP under
subpart P. This provides operators the
choice to manage the safety of farm tap
regulators under either DIMP or the
§ 192.740 inspection requirement.
Finally, the NPRM included a
proposal to exempt farm tap service
lines connected to unregulated
gathering or production pipelines from
annual reporting (§ 191.11), farm tap
regulator maintenance (§ 192.740), and
DIMP (part 192, subpart P). Any portion
of a farm tap that meets the definition
of a service pipeline at § 192.3 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 service line connected to a
production pipeline must have an
operator identification number in
accordance with § 191.22 and must
submit gas distribution incident reports
for incidents that occur on the service
line (§ 191.9). While the operator’s
production pipeline is exempt from part
191 (see § 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.
2. Summary of Public Comments
Several commenters suggested
PHMSA should simplify how farm tap
requirements are presented in the PSR.
The American Association of Laboratory
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Accreditation (A2LA) recommend
adding a provision requiring that those
entities conducting inspections achieve
and maintain ISO/IEC 17020
(Conformity Assessment-Requirements
for the Operation of Various Types of
Bodies Performing Inspection)
accreditation. The FreedomWorks
Foundation (FreedomWorks)
commented that the proposed changes
in the NPRM would especially benefit
smaller operations burdened by the high
cost of compliance upon startup. PST
commented the proposed PSR
amendments appear to demonstrate an
equivalent level of safety and they do
not oppose this change. One company
provided an editorial suggestion that the
last word in proposed § 192.740(c)(3)
should be ‘‘or’’ to clarify that this
section (§ 192.740) does not apply if any
one of the listed conditions apply.
Several commenters commented on
farm tap-related terms and definitions
proposed in § 192.740. Sander
Resources suggested there were at least
two significant definitional issues
contained within the proposed rule that
confused farm tap operators. The first
relates to ‘‘unregulated . . . gathering.’’
Sander Resources commented that,
technically, there is no such thing as
‘‘unregulated gathering.’’ All gathering
lines are subject to the jurisdiction of
PHMSA, but some are exempted from
the requirements of part 192 as specified
in § 192.9. Thus, this reference could be
interpreted to mean that all gathering
lines are still subject to the requirements
of § 192.740 or § 192.1003 and related
provisions, which could encompass
much of part 192. They recommended
that PHMSA clarify what it means to be
‘‘unregulated,’’ possibly through a
reference to whether a line is subject to
regulation under § 192.9. The Gas
Piping Technology Committee (GPTC)
similarly suggested that PHMSA clarify
that regulated and unregulated gathering
lines are as determined in § 192.8.
Sander Resources (on behalf of the
Independent Petroleum Association of
America, or IPAA) also raised a concern
related to the definition of ‘‘service
line’’ and, in particular, language in the
NPRM’s preamble suggesting that the
part 192-regulated ‘‘service line’’
portion of a farm tap would begin at the
‘‘first aboveground point where
downstream piping can be isolated from
source piping (e.g., a valve or regulator
inlet).’’ AGA, API, the American Public
Gas Association (APGA), and INGAA
(collectively, AGA et al.) jointly
submitted a similar comment
recommending against PHMSA defining
the ‘‘service line’’ portion of a farm tap
in the proposed amendment to
§ 192.740. They commented it is neither
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practicable nor necessary for safety to
define a uniform starting point for the
service line on every farm tap directly
connected to a transmission line. Their
preferred approach would be to
incorporate a distribution center
definition that allows farm tap piping to
be classified as a distribution center and
explicitly allow operators to designate
piping as transmission, even if the
pipeline could be classified as
distribution under the existing § 192.3.
Rather than defining where the ‘‘service
line’’ starts for farm taps under part 192,
TC Energy commented PHMSA should
revise § 192.740 to apply to ‘‘pipelines’’
serving farm tap customers instead of
‘‘service lines,’’ and eliminate the
description of the source of supply to
the farm tap customer. TC Energy
believes that these changes would
maintain the intended protections to
farm tap customers and address
industry concerns. A private citizen
similarly commented that, in addition to
these clarifications, PHMSA should
clarify the definitions for transmission
lines and distribution centers.
GPA Midstream stated that they did
not support the NPRM preamble
statement that, on a farm tap, the
boundary between source piping and
the distribution service lines is the first
aboveground isolation point
downstream from the source piping.
They stated that there is no legal basis
for using that point to delineate where
a source production, gathering, or
transmission line ends and a gas
distribution service line under part 192
begins in a farm tap configuration. GPA
Midstream urged PHMSA to
acknowledge in the final rule that an
operator may exercise reasonable
discretion in determining where source
piping ends and distribution service
line piping, if any, begins in farm tap
configurations. The Independent Oil
and Gas Association of West Virginia
(IOGAWV) commented PHMSA should
not attempt to use its authority to
change private contracts by transferring
the cost of complying with the PSR to
producers and unregulated gathering
line operators. IOGAWV and the Ohio
Oil and Gas Association (OOGA) stated
PHMSA should take this opportunity to
exempt farm taps from the PSR. IPAA
urged PHMSA to recognize the
significant difference between privatelyowned farm taps, governed by contract
or statute, and true distribution systems.
GPA Midstream reiterated concerns
with the definition of the start of a
service line and the applicability of part
192 to farm taps connected to
production lines and unregulated
gathering lines in supplemental
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comments submitted after the GPAC
meeting.
The GPAC voted unanimously in
favor of the PSR amendments proposed
in the NPRM, provided that PHMSA
remove § 192.740(c)(4), thus eliminating
language implying where a service line
starts on a farm tap.
3. PHMSA Response
The final rule adopts the amendments
with respect to farm taps as proposed in
the NPRM, but revises the proposed
§ 192.740 as discussed below. PHMSA
determined that compliance with the
pressure regulator inspection
requirements in § 192.740 or
compliance with DIMP provide an
equivalent level of safety. DIMP does
not include specific, prescriptive
inspection requirements for pressure
regulating devices; however, operators
are required by § 192.1007 to evaluate
risks due to equipment failure under
DIMP, which includes pressure
regulating devices. Accordingly, farm
tap operators must consider
overpressure risk due to regulator
failure in their DIMP, especially if the
source pipeline pressure is very high.
While § 192.740 is focused on pressure
regulator maintenance, DIMP is a
broader safety program that requires
operators identify, evaluate, rank, and
mitigate a wide range of risks to
pipeline safety. Either requirement
provides safety to farm tap customers by
reducing the probability of a regulator
system malfunction and, in the case of
DIMP, incidents caused by other threats
such as excavation damage and
corrosion. Therefore, this change
provides greater flexibility for operators
of these farm taps while still requiring
that operators evaluate all equipment to
protect against failures and protect
human health and the physical
environment.
This proposed amendment was
intended to provide flexibility for farm
tap operators. It was not designed to
resolve more general definitional
questions surrounding the topic of farm
taps. Therefore, PHMSA agrees with the
suggestion to remove the proposed
§ 192.740(c)(4) from the final rule,
which implied where the source piping
on a farm tap ends and distribution,
transmission, or customer piping begins.
PHMSA believes that this change
resolves most of the concerns about
definitional changes raised by
commenters. To the extent that there are
remaining questions surrounding farm
taps following this rulemaking, PHMSA
will use ongoing efforts such as the
proposed Farm Taps Frequently Asked
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Questions (FAQs); 16 the remaining
rulemaking projects associated with the
Safety of Gas Transmission and Gas
Gathering Pipelines NPRM; 17 and, if
necessary, additional rulemaking and
guidance. While the comment from TC
Energy sidesteps these definitional
issues, and has the benefit of extending
protection to farm taps that operate at
greater than 20 percent of specified
minimum yield strength (SMYS) (and
are therefore classified as transmission
lines rather than service lines pursuant
to the definition of a transmission line
in § 192.3), it requires defining an
additional term (‘‘farm tap customer’’)
which was not made available for public
comment in the NPRM or discussed by
other comments in the rulemaking
docket.
While this final rule does not define
the boundaries of that portion of a farm
tap that is regulated as a service line
under part 192, the fact that a farm tap
may include a regulated service line
remains unchanged. Therefore, PHMSA
disagrees with comments that the
NPRM’s characterization of portions of
farm taps as jurisdictional service lines
creates ‘‘entirely new’’ legal obligations
for operators of service lines who also
operate non-jurisdictional production
lines and rural gathering lines that are
not subject to safety regulation under
part 192. Removing farm taps connected
to production lines and unregulated
gathering lines from the scope of the
entire PSR, as suggested by some
commenters, would be a consequential
change from longstanding regulatory
application and is beyond the scope of
this final rule.
PHMSA and its predecessor agencies
have been explicit and consistent with
respect to the applicability of the part
192 regulations to distribution service
lines in farm tap applications since the
earliest years of Federal gas pipeline
safety oversight. The Office of Pipeline
Safety revised the definition of a service
line in § 192.3 to clarify the point at
which a service line ends and customer
piping begins in an NPRM entitled,
‘‘Minimum Federal Safety Standards for
Transportation of Natural and Other Gas
by Pipeline: Definition of Service Line,’’
published on April 10, 1971.18 On April
10, 1973, PHMSA finalized the proposal
and defined the downstream end of a
16 85
FR 21820 (Apr. 20, 2020).
2137–AF39 (Pipeline Safety: Safety of Gas
Gathering Pipelines) and 2137–AF38 (Pipeline
Safety: Safety of Gas Transmission Pipelines, Repair
Criteria, Integrity Management Improvements,
Cathodic Protection, Management of Change, and
Other Related Amendments), associated with
PHMSA, ‘‘Notice of Proposed Rulemaking:
‘‘Pipeline Safety—Safety of Gas Transmission and
Gathering Pipelines,’’ 81 FR 20721 (Apr. 8, 2016).
18 36 FR 9667.
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17 RINs
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service line as the customer meter or
connection to customer piping,
whichever is further downstream.19
This boundary stands with minor
clarifications to this day at § 192.3.
PHMSA formulated the definition of
‘‘service line’’ to address service lines in
farm tap applications and other
situations where no meter is present.
PHMSA’s predecessor agency, the
Research and Special Programs
Administration, again acknowledged the
regulated status of service lines in farm
tap applications in a final rule titled,
‘‘Pipeline Safety: Customer-Owned
Service Lines’’ issued on August 14,
1995.20 Finally, providing gas to farm
tap customers is not a defined gathering
or production function in either § 192.3
or in API Recommended Practice (RP)
80 (incorporated by reference in
§ 192.7). While production pipelines
and some gathering pipelines are not
subject to safety regulation under part
192, the distribution of national gas to
customers is subject to PHMSA
jurisdiction (49 U.S.C. 60101(a)(21)(i))
and the applicability of part 192
(§§ 192.1(a), 192.3) regardless of other
activities in which an operator may also
be engaged.
Regarding operators’ concerns about
their responsibility for customer-owned
piping that they do not own or have
access to, PHMSA reiterates that the
final rule imposes no new requirements
on operators of service lines in farm tap
applications. Section 192.3 provides
that a service line ends at the
connection to customer-owned piping,
or the outlet of the meter, whichever is
further downstream. In the preamble to
the 1995 customer-owned service line
rule described above, PHMSA explained
that that the PSR applies to the
distribution of gas up to the end of a
pipeline operator’s service line.21 In an
earlier interpretation, PHMSA also
noted that customer piping downstream
of the end of a service line as defined
in § 192.3 is not subject to part 192,
provided the gas is for the customer’s
own use.22 Therefore, the PSR does not
require the source pipeline operator to
maintain customer-owned piping
downstream of the customer meter as
defined in § 192.3. If there is no
customer meter, then the service line
terminates at the connection to
customer-owned piping. Some operators
do maintain customer piping
voluntarily or as required by State,
FR 9083.
FR 41821.
21 60 FR 41821.
22 PHMSA Interpretation #PI–73–0110 (June 6,
1973), https://cms7.phmsa.dot.gov/regulations/
title49/interp/PI-73-0110.
local, or contractual requirements. If an
operator of a service line does not
maintain the customer’s piping under
such arrangement, then the customer
notification requirements in § 192.16
may apply.
PHMSA agrees with certain comments
to clarify language in § 192.740. In the
final rule, PHMSA has replaced the term
‘‘unregulated gathering line’’ with a
gathering line other than a regulated
gathering line as determined in § 192.8.
In other words, a gathering line as
determined in accordance with § 192.8
and API RP 80, but excluding a Type A
or Type B regulated gathering line as
defined in § 192.8. In addition, the
exceptions in paragraph (c) are now
separated by an ‘‘or’’ in the final rule.
Lastly, because the PSR revisions
adopted in this final rule obviate the
need for its March 29, 2019 ‘‘Exercise of
Enforcement Discretion Regarding Farm
Taps,’’ 23 PHMSA withdraws that
document as of the effective date of this
final rule.
B. Master Meter Operators (Sections
192.1003, 192.1005, 192.1015)
1. PHMSA’s Proposal
In the NPRM, PHMSA proposed to
revise §§ 192.1003, 192.1005, and
192.1015 to exempt master meter
operators from DIMP requirements. A
‘‘master meter system’’ is defined at
§ 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 meter systems include owners
of apartment complexes or mobile home
parks who provide or sell gas to tenants.
Unlike most gas distribution operators,
delivering gas is typically not a master
meter operator’s primary business.
When DIMP requirements were first
proposed in 2008,24 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 DIMP requirements that master meter
operators could easily implement and
that would enhance safety. However,
PHMSA has determined that Section
192.1015 requirements are neither easily
implemented nor do they enhance
safety. Master meter operators have
struggled to implement the relatively
simple master meter systems DIMP
requirements that were designed for
19 38
20 60
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23 84
FR 11253.
‘‘Notice of Proposed Rulemaking:
Integrity Management Program for Gas Distribution
Pipelines,’’ 73 FR 36015 (June 25, 2008) (DIMP
NPRM).
24 PHMSA,
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complex gas distribution systems. In
addition, PHMSA determined that there
is no safety benefit from applying even
that limited set of DIMP requirements to
master meter systems, as compliance
with other applicable pipeline safety
regulations in part 192 provides robust
assurance of public safety. The
applicable part 192 requirements that
PHMSA considered include, but are not
limited to, operations and maintenance
requirements at subpart L and subpart
M, continuing surveillance
requirements at § 192.613, and the
failure investigation requirement at
§ 192.617.
2. Summary of Public Comments
Several commenters generally
supported exempting master meter
operators from the DIMP requirements
in part 192. These commenters
(including the National Propane Gas
Association (NPGA), the National
Association of Pipeline Safety
Representatives (NAPSR), AmeriGas,
and Superior Plus Propane (SPP))
agreed with PHMSA’s characterization
of master meter systems as generally
small, simple systems that see little
benefit from DIMP compliance. These
commenters agreed that compliance
with existing subparts A through N of
part 192 is sufficient to ensure the safety
of small, simple master meter systems.
They asserted that the current
requirement of subpart P to create a
DIMP, even using the SHRIMP tool,25
consumes significant additional time
and resources with little or no safety
benefit, noting that the result of the
process for master meter systems is
typically a determination that there is
no need for additional mitigating
actions on any portion of the pipeline
system. As a result, the commenters
stated that the time and resources
expended to comply with the DIMP
requirements have no meaningful safety
benefits for such systems. The PST
commented that they do not oppose this
change, but urged PHMSA and its State
partners to ensure that master meter
operators are managing the integrity
risks to their systems outside the
context of a DIMP.
PHMSA also received comments
concerning similar DIMP requirements
for small liquefied petroleum gas (LPG)
distribution pipeline systems. A ‘‘small
LPG operator’’ is defined in § 192.1001
as a liquefied petroleum gas distribution
system that serves fewer than 100
customers from a single source. Small
LPG operators are currently required to
comply with the same DIMP
requirements as master meter systems.
Several commenters (including NPGA,
NAPSR, AmeriGas, and SPP)
commented that jurisdictional propane
pipeline systems are like master meter
systems and therefore small LPG
operators should be exempt from the
DIMP requirements as well. They
commented that small LPG systems are
comparable to master meter systems in
size and application. Like master meter
systems, the commenters claimed the
majority of small LPG pipeline systems
are single-property systems that occupy
a small overall footprint in size,
generally operate at a single operating
pressure, and have no equipment other
than pipe, meters, regulators, and
valves. They commented that small LPG
systems typically serve 25 customers or
less, and facilities such as those at RV
parks or strip malls can have as few as
three customers; very few small LPG
systems serve more than 100 customers.
One anonymous commenter associated
with an LPG system stated that the
DIMP process is lengthy and
unnecessary, and that in their
experience, many of the prompts on the
DIMP form 26 do not make sense given
the layout of a small LPG utility. NAPSR
stated that many of these smaller
systems identify only third-party
damage as a major threat to the system,
and a DIMP requires a considerable
amount of work for a very small amount
of safety benefit.
Commenters representing LPG
suppliers (including AmeriGas, SPP,
and NPGA) noted that with regard to the
PSR, the regulated entity is the entity
that owns the pipeline and receives the
operator ID issued by PHMSA for that
pipeline system. They stated that in
many cases, the LPG supplier does not
operate the pipeline and their primary
business is to transport gas by delivery
truck, not pipelines. They further stated
that most are contractors to the entity
that owns the pipeline and the pipeline
operator ID for the system. They stated
that many of these master meter
operators use contractors for service, but
those contractors are not the operators
under part 192. These commenters
agreed that the other part 192
requirements continue to apply to
provide adequate requirements for small
LPG systems in the absence of DIMP
requirements. They also stated that in
addition to the requirements in part 192
applicable to all gas distribution
pipelines, § 192.11 requires LPG
26 PHMSA
25 The ‘‘Simple, Handy, Risk-based Integrity
Management Plan’’ tool published by the APGA
Security and Integrity Foundation.
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Gas Distribution Integrity Assessment
Question Set, available at https://
www.phmsa.dot.gov/forms/phmsa-gas-distributionia-question-set-pdf.
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distribution systems to comply with a
National Fire Protection Association
(NFPA) standard, NFPA 58 (LP-Gas
Code) or NFPA 59 (Utility LP-Gas Plant
Code), which contains comparable and
supplemental provisions that address
safety. They asserted that the additional
requirements of DIMP do not add a
measure of safety beyond the provisions
in part 192 and NFPA 58.
AmeriGas and NPGA estimated that
extending the NPRM’s proposed DIMP
exemptions for master meters to small
LPG systems could result in $1.12
million in annualized cost savings; this
estimate was calculated by applying the
cost estimates in the RIA to an estimate
of the number of small LPG operators in
Safety Regulation for Small LPG
Distribution Systems, a report published
in 2018 by the Transportation Research
Board (TRB).27 The commenters
asserted that these additional savings
would further PHMSA’s goal of
reducing regulatory impact burdens.
The commenters also stated that these
estimated savings to the industry would
allow small LPG operators to devote
more of their resources in other areas of
safety.
NAPSR suggested that small
distribution utilities with 100 or fewer
customers should also be exempted
from the DIMP requirements, stating
that many master meter systems, small
distribution systems and small LPG
systems typically have no threats
beyond the minimum threats listed in
§ 192.1015(b)(2).
The GPAC voted unanimously in
favor of PHMSA’s proposed amendment
with respect to the applicability of
DIMP requirements to master meter
systems. The GPAC did not recommend
changes to DIMP requirements for small
LPG systems or small distribution
systems.
3. PHMSA Response
The final rule revises §§ 192.1003,
192.1005, and 192.1015 to eliminate
DIMP requirements for master meter
systems as proposed in the NPRM.
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 State inspection and operator
maintenance effort was being used to
improve DIMP compliance among
master meter operators. Despite these
27 TRB, Transportation Research Board Special
Report 327: Safety Regulation for Small LPG
Distribution Systems (2018), https://www.nap.edu/
catalog/25245/safety-regulation-for-small-lpgdistribution-systems.
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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 may be
better used to implement other part 192
safety requirements effectively that
master meter system operators will
remain obliged to follow.
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 DIMP NPRM
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 comprehensive management
system like DIMP is not required to
integrate data and information to
identify risk mitigation strategies and
actions. PHMSA’s experience indicates
that the analysis and documentation
requirements of DIMP have had little
safety benefit for this type of operator.
And, anecdotally, PHMSA and State
enforcement personnel have advised
that focusing on more fundamental risk
mitigation activities (particularly those
required by §§ 192.605 (Procedural
manual for operations, maintenance,
and emergencies), 192.613 (Continuing
surveillance), and 192.617
(Investigations of failures)) yields 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.
Considering the burden on finite State
inspection resources, implementation
difficulties, and the limited safety
benefits of DIMP compliance for master
meter systems described above, PHMSA
believes there could even be potential
safety benefits because operators and
inspectors can prioritize more pertinent
compliance activities specific to master
meter systems.
PHMSA appreciates the comments
regarding the applicability of DIMP
towards small LPG operators and
acknowledges that many small LPG
systems have configurations like master
meter systems. However, PHMSA
believes that the decision about whether
to extend the DIMP exception to such
facilities or to all distribution systems
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with fewer than 100 customers would
benefit from additional safety analysis
and notice and comment procedures
prior to further consideration. In 2018,
the TRB published a report on Federal
safety standard for small LPG systems.
The TRB’s recommendations focused on
clarifying the definition of a ‘‘public
place’’ and improving State inspection
programs. While the TRB suggested that
a PHMSA-supervised State waiver
process could be appropriate, it did not
recommend exempting all small LPG
systems from DIMP or any other
requirement. PHMSA will continue to
evaluate the issue of DIMP requirements
for small LPG systems and, if
appropriate, propose changes in a future
rulemaking giving due consideration to
the public comments on the NPRM, the
recommendations of the GPAC, and the
TRB report. For similar reasons, PHMSA
has also not adopted suggestions from
commenters to exempt other
distribution operators with fewer than
100 customers.
Reporting and Information Collections
C. Mechanical Fitting Failure Reporting
(Sections 191.12, 192.1009)
1. PHMSA’s Proposal
On February 1, 2011, PHMSA issued
the final rule, ‘‘Pipeline Safety:
Mechanical Fitting Failure Reporting
Requirements’’ 28 adding §§ 191.12,
192.1001, and 192.1009 to the PSR.
Section 191.12 sets forth the
requirement for operators to report
mechanical fitting failures (MFFs)
through DOT Form PHMSA F–7100.1–
2 (MFF report form). 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 joint, the
majority of which are low-consequence
or no-consequence events that do not
meet the definition of an incident at
§ 191.3. These requirements expanded
an earlier requirement established in the
December 4, 2009 DIMP final rule that
was limited to mechanical couplings
used to join plastic pipe.29 The DIMP
final rule adopted the MFF report
requirement as a result of investigations
of incidents caused by poorly designed
or improperly installed mechanical
joints throughout the pipeline industry.
PHMSA initially sought to collect these
data in 2011 to determine the frequency
of mechanical joint failures and identify
the most common characteristics of
those failures.30 The 2009 DIMP final
FR 5494.
FR 63905.
30 76 FR 5495.
Fmt 4701
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29 74
Frm 00008
31 DOT
32 https://www.phmsa.dot.gov/pipeline/gas-
28 76
PO 00000
rule was part of a broader effort by
PHMSA and the gas distribution
pipeline industry to identify potential
safety issues with plastic gas pipelines.
Like the Gas Distribution Incident
Report form,31 the MFF report form
requires operators submit information
on the design and installation of the
failed fitting and the apparent cause of
the failure. The MFF report form also
includes manufacturing information;
however, this is generally not known by
the operator and therefore is reported as
‘‘unknown.’’ MFF reports are required
for any failure of a mechanical joint
other than those that result in a ‘‘nonhazardous leak,’’ as opposed to Gas
Distribution Incident Reports, which are
required only for events that meet the
criteria for reportable ‘‘incidents’’ in
§ 191.3. Operators report any
‘‘hazardous leak’’ as that term is defined
at § 192.1001. The criteria for a
‘‘hazardous leak’’ does not depend on
an outcome severity threshold.
Approximately 15,000 MFF reports are
submitted to PHMSA each year,
compared to approximately 100 Gas
Distribution Incident Reports due to all
causes. PHMSA publishes a report on
the information collected and its
analysis of the information received
annually, which is available online.32
PHMSA determined that further
collection of MFF reports has limited
value, and proposed to remove
§§ 191.12 and 192.1009, eliminating the
requirement for operators to submit
MFF reports through DOT Form
PHMSA F–7100.1–2. PHMSA
understands from analyzing MFF report
forms received over the last decade that
the purposes of this reporting
requirement have been realized:
PHMSA’s analysis of data from MFF
reports confirmed its expectations
regarding MFF characteristics and
causes, and pipeline operators have
become much more sensitive to MFFs.
PHMSA considered that operators
would still be required to submit
incident reports via a modified version
of the Gas Distribution Incident Report
form (which would include most of the
information on the MFF report form) for
releases from mechanical fittings that
meet the definition of an incident at
§ 191.3. Part G5–5 of the Gas
Distribution Incident Report form
currently requires operators to identify
the MFF report number for incidents
involving an MFF; PHMSA therefore
proposed to replace this cross-reference
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with the fitting, manufacturer, and
failure information that is currently
collected on the MFF report form.
PHMSA also proposed to revise the Gas
Distribution Annual Report form 33 to
include a count of hazardous leaks
involving a mechanical joint failure.
This issue was raised in comments
submitted in response to the DOT
Notification of Regulatory Review from
the Associations, the Gas Piping
Technology Committee (GPTC), and the
West Virginia Oil and Natural Gas
Association (WVONGA), which
identified the MFF reporting
requirement as an unnecessary and
burdensome information collection.
2. Summary of Public Comments
Several commenters (including
AmeriGas, NPGA, SPP, Dresser Natural
Gas Solutions, the Norton McMurray
Manufacturing Company (NORMAC),
Oleksa and Associates, the Plastics Pipe
Institute (PPI), and a private citizen)
supported eliminating the MFF
reporting requirement. Dresser
contended that PHMSA has found these
data do not provide meaningful trends
related to risk of pipeline leaks. PPI
stated that the removal of this regulatory
reporting burden reduces the
unnecessary focus on mechanical
fittings as a potential source of
incidents. NORMAC agreed that MFF
reporting has not provided statistically
significant trends or information upon
which operators or regulators can act.
Several commenters (including
AmeriGas, SPP, and NPGA) expressed
concerns regarding PHMSA’s proposal
to modify the Gas Distribution Annual
Report form to collect data on the
number of mechanical joint failures.
Those commenters opposed including a
count of leaks involving mechanical
joints on the Gas Distribution Annual
Report form, noting that if limited value
was derived from independent MFF
reporting, it is reasonable to conclude
that there would be limited value in
tracking and reporting the number of
MFFs on revised Gas Distribution
Annual and Incident Report forms.
NORMAC commented that part C of the
current Gas Distribution Annual Report
form requires each operator to report the
total number of leaks and how many
were classified as hazardous based upon
the cause of the leak. The instructions
provided for completion of part C
describe each classification of cause in
detail in terms of what is being
requested of an operator. NORMAC
noted that modifying the Gas
Distribution Annual Report form as
proposed will lead the user to jump to
33 DOT
Form PHMSA F 7100.1–1.
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the conclusion that any leak involving
a mechanical joint arises from the
mechanical fitting being ‘‘faulty,’’ when
the leak may be caused by improper
installation by the operator and should
therefore be coded as caused by
‘‘Incorrect Operation.’’ GPTC
commented that reporting leaks caused
by mechanical joint failure would repeat
reporting of leaks caused by ‘‘pipe,
weld, or joint failure’’ and potentially be
confusing for operators. They further
commented that the leak information is
intended to be general in nature and not
intended to capture the ‘‘laboratory
analysis’’ for eliminated leaks.
Regarding the proposed changes to
Gas Distribution Incident Report form,
NORMAC expressed concerns with the
NPRM’s proposal to incorporate existing
data fields in the current MFF report
within part G (Apparent Cause), subcause G5 (Pipe, Weld, or Joint Failure)
of a revised Gas Distribution Incident
Report form. NORMAC noted that the
cause of a failure may not be due to
Pipe, Weld, or Joint Failure.
Specifically, they noted that fittings that
fail due to improper installation are
required to be categorized under the
‘‘Incorrect Operation’’ cause. NORMAC
also mentioned that Question 12 under
sub-cause G5 (Pipe, Weld, or Joint
Failure) duplicate what sub-cause G7
(Incorrect Operation) is asking.
NORMAC stated that requiring
respondents to answer the same
question under two categories will lead
to confusion and make effective analysis
of the resulting database difficult.
NORMAC submitted text revisions to
sub-cause G5 of the Gas Distribution
Incident Report form and associated
instructions.
Dresser raised similar concerns with
both the Gas Distribution Annual Report
and the Gas Distribution Incident Report
forms, in addition to noting that there
could be confusion concerning the
difference between a mechanical fitting
and a mechanical joint. Dresser noted
that the existing categories support the
reporting of pipeline failures where
mechanical fittings may be involved
under the existing categories of ‘‘Weld
Pipe or Joint Failure’’ or ‘‘Incorrect
Operation’’ depending on the causal
factors being a manufacturing or design
defect for the former or a deficiency in
the field installation practice or
improper application for the latter.
NORMAC also supported addressing the
distinction between ‘‘mechanical
fitting’’ and ‘‘joint’’ to ensure that the
regulatory oversight activity focus on
joints, the making of joints, and the
qualifying of joining procedures.
Theresa Pugh Consulting commented
that PHMSA should revise the Gas
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2217
Distribution Incident Report form to
include whether industrial and power
sector customers were notified of a
curtailment in gas supply following an
incident and the duration of such
disruption. The commenter stated the
form should allow the operator to state
if gas supply was maintained by redirecting natural gas at full contracted
capacity to the customer through reverse
flow or through alternative parties. The
commenter noted that the power and
industrial customers would benefit from
a way to determine during contract
negotiations whether the company they
wish to purchase gas from has a sound
and reliable safety program, but
acknowledged challenges with ensuring
that such information is not in a format
that could be used by competitors to
reverse engineer operational
information about industrial customers
such as plastics manufacturing plants.
The commenter recommended that
PHMSA should expand rather than
shrink the reporting measures on its
reporting forms.
NORMAC commented that burden on
operators can be drastically reduced
beyond what the proposed rulemaking
proposes by also eliminating the portion
of Plastic Pipe Database Collection
(PPDC) reporting conducted by the
American Gas Association that deals
with mechanical joints. NORMAC
commented that the PPDC is nearly
identical to the MFF and has also not
shown useful trends. NORMAC also
asserted that recording and reporting
mechanical joint leaks through PPDC is
not as effective as addressing the
problem directly within each operator’s
IM program. NORMAC suggested that
PHMSA propose the discontinuation of
this reporting effort in its role as PPDC
chair.
PST opposed eliminating the MFF
report requirement. They questioned
whether this would prevent PHMSA
from becoming aware of thousands of
MFFs per year, many of which result in
hazardous and potentially explosive
leaks, others of which result in nonexplosive but hazardous leaks of
methane into the atmosphere. The
commenter stated these circumstances
would also not typically be reported as
a safety-related condition, because of
the many exemptions and exceptions to
the safety-related condition reports
listed in § 191.23(b). PST asserted the
detailed information on MFFs is
currently gathered so that PHMSA can
identify any patterns among those
failures, either by geography or failure
type or any other common parameter.
Limiting the detailed reporting in the
MFF report to reportable incidents
eliminates another source of
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information of leading indicators of
problems common among operators, one
that nets information on 15,000 fitting
failures each year.
The GPAC voted 13–2 in favor of
PHMSA’s proposed amendment to
eliminate the MFF reporting
requirement. PST and the
Environmental Defense Fund (EDF)
voted against the proposed amendment.
During the GPAC discussions, PST
reiterated its reservations regarding
reducing the availability to PHMSA and
other safety regulators of information on
hazardous leaks. PST also opined that
eliminating MFF reporting may reduce
operators’ incentives to improve
mechanical fitting performance. EDF,
meanwhile, contended that the MFF
report data being eliminated could
prove helpful to Federal and State
environmental regulators and public
service commissions in evaluating the
significance of methane emissions from
service line couplings.
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3. PHMSA Response
In the final rule, PHMSA is adopting
the amendments to MFF reporting
requirements at §§ 191.12 and 192.1001
as proposed in the NPRM. PHMSA is
also retaining the proposed requirement
to include a count of MFFs on the Gas
Distribution Annual Report form and
revision of the Gas Distribution Incident
Report form to include information from
the MFF report for incidents involving
a failure of a mechanical joint.
PHMSA’s 2018 analysis of MFF data
reports obtained to date confirm
PHMSA’s expectations regarding the
frequency and characteristics (including
material, type, location, and vintage of
fittings) of MFFs when it began this
information collection activity under
the DIMP final rule.34 The 2018 analysis
further notes that the MFF reports
submitted in the preceding year show
similar trends to the previous 5 years,
and that all changes were within the
expected variance. These findings
mirror the conclusions of PHMSA’s
earlier, 2016 analysis of the MFF reports
submitted in the then-preceding 5 years
(2011–2015).35 Because MFF report data
reviewed in 2018 and 2016 confirmed
PHMSA’s expectations regarding the
frequency and characteristics of
mechanical joint failure without
34 PHMSA, Analysis of Data from Required
Reporting of Mechanical Fitting Failures that Result
in a Hazardous Leak (§ 192.1009) at 47–48 (Jul. 4,
2018), https://www.phmsa.dot.gov/sites/
phmsa.dot.gov/files/docs/technical-resources/
pipeline/gas-distribution-integrity-management/
66046/mffr-data-analysis-procedure-2017-datareport-final-07-04-2018.pdf.
35 PHMSA, Analysis of Data from Required
Reporting of Mechanical Fitting Failures that Result
in a Hazardous Leaks (§ 192.1009) (Oct. 15, 2016).
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yielding new statistically significant
causal or predictive insights, PHMSA
has determined that additional
information collection via a dedicated
MFF report form is unnecessary.
PHMSA further notes improvements
in fitting design, operator joining
practices, and Federal safety
requirements since the introduction of
the MFF reporting requirement have
improved the safety of mechanical
fittings on newer installations.
PHMSA’s 2018 analysis of MFF report
data reached a similar conclusion,
noting that many operator DIMPs are
sensitive to the risk of MFF following
the introduction of the MFF reporting
requirement. However, PHMSA’s 2018
analysis notes that the number of
operators submitting MFF reports has
stayed approximately the same for the
last several years—suggesting that any
action-forcing benefit hypothesized has
been realized and that the benefits from
continuing a dedicated MFF reporting
requirement may be negligible.
The modifications to other reports
adopted in this final rule will help
PHMSA ensure continued availability of
information needed to provide effective
regulatory oversight of MFFs. Leaks
from mechanical joints are already
aggregated within the broader categories
on the existing Gas Distribution Annual
Report form. The revised Gas
Distribution Annual Report form
requires reporting the number of leaks
involving mechanical joint failures in
addition to the existing, aggregated
categories. This change is expected to
provide sufficient information to track
the safety performance of mechanical
joints over time, among operators, or
across the industry. These data are
expected to provide operators, PHMSA,
and State inspectors sufficient
information to identify if action is
needed under DIMP or other elements of
operator programs for compliance with
part 192 requirements.
PHMSA is also revising the Gas
Distribution Annual Report form to
identify the number of leaks involving
a mechanical joint failure as a separate
line item from the count of leaks by
cause. However, to address the potential
confusion raised by commenters,
PHMSA will revise the proposed part C
of the Gas Distribution Annual Report
form to clarify that operators should
report the number of hazardous leaks
‘‘involving’’ a mechanical joint failure,
rather than ‘‘caused’’ by a mechanical
joint failure. This aligns with the
language in the current MFF report
requirement and is clearer. PHMSA will
further clarify in the form instructions
that the count of leaks involving a
mechanical joint failure is separate and
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in addition to the leaks by cause.
Operators should continue to report all
leaks by cause in the table in part C of
the Gas Distribution Annual Report
form as they have been doing
previously, while the new count at the
end of part C consists of a count of
hazardous leaks involving the failure of
a mechanical joint regardless of whether
the leak was caused by equipment
failure, incorrect operation/installation,
or other causes. Likewise, on the Gas
Distribution Incident Report form,
operators should continue to report
incidents involving a failure of a
mechanical joint that was caused by
improper installation under the
‘‘incorrect operation’’ cause under
section G7 of the Gas Distribution
Incident Report form. The revised Gas
Distribution Incident Report form will
not require operators to submit design
and manufacturing information about
incidents involving mechanical joints
that were caused by incorrect operation
rather than material, weld, or equipment
failure.
PHMSA appreciates the concerns
raised by commenters and members of
the GPAC about reducing the data
available to PHMSA and other
stakeholders through changes in
reporting requirements proposed in the
NPRM and adopted in this final rule.
PHMSA agrees that access to quality
safety-related information is critical to
implementation of an effective
regulatory and enforcement program.
However, these safety programs benefit
from the flexibility both to create
targeted information collection activities
to address safety issues and to remove
those information collection activities
that are no longer necessary or have not
proven useful. Here, PHMSA has
determined that its original purpose for
introducing a dedicated MFF reporting
requirement has been satisfied.
Although PHMSA could posit new
justifications (e.g., use by environmental
regulators and utility commissions in
calibrating regulatory oversight of
service line couplings) for this
dedicated reporting requirement, it
declines to do so in this rulemaking.
Nevertheless, PHMSA submits that
Federal and State regulators’ oversight
activities may continue to benefit from
nearly a decade of historical, granular
data obtained from MFF reports,36 in
addition to the operator-specific MFF
data that PHMSA will collect in the Gas
36 PHMSA makes such raw data available on its
website at https://www.phmsa.dot.gov/data-andstatistics/pipeline/mechanical-fitting-failure-datagas-distribution-operators.
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Distribution Annual and Incident
Report forms modified by this final rule.
Replacing the full MFF report with a
count of MFFs on the Gas Distribution
Annual Report results in a reduction in
reporting burden for each event but
without a significant loss of useful
information to operators and PHMSA.
Although the revised requirements
eliminate the detailed information on
each mechanical fitting failure, this
information has not yielded meaningful
new causal or predictive insights
regarding leaks involving mechanical
joints. On the other hand, the general
count of leaks involving a mechanical
joint failure as required in the revised
Gas Distribution Annual Report is not
burdensome to compile yet provides
information on the relative safety
performance of mechanical joints in
general. This information remains
valuable to PHMSA and State agencies
for safety performance monitoring and
for prioritizing inspections. PHMSA has
determined that incident reporting
requirements via a revised Gas
Distribution Incident Report form and
the revision to the Gas Distribution
Annual Report form to include a count
of hazardous leaks involving a
mechanical joint failure is sufficient to
identify the total number of hazardous
leaks involving mechanical joint failures
and identify trends over time and
among States or operators.
Nor does this change absolve
operators of other safety requirements
that apply when leaks at MFFs are
discovered. PHMSA requires that gas
pipeline operators have procedures for
investigating failures under § 192.617 to
determine the causes of the failure and
minimize the possibility of a recurrence.
PHMSA also requires operators repair
hazardous leaks promptly under
§ 192.703. These requirements apply
regardless of whether the failure results
in a reportable leak or incident. Finally,
operators are required to consider leak
history under the continuing
surveillance requirements at § 192.613
and under their DIMP (§ 192.1007(b),
(d), and (e)). PHMSA accordingly finds
that the PSR change adopted in this
final rule eliminates an unnecessary
reporting burden without an adverse
impact on safety.
Many of the comments received
pertained to related topics on the Gas
Distribution Incident and Annual
Report forms and are not directly related
to the reporting of mechanical joint
failures. PHMSA will consider these
comments during periodic updates and
renewals of these information
collections pursuant to the Paperwork
Reduction Act. PHMSA does not have
authority over voluntary information
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collection organized by other, nongovernmental entities and therefore the
comment related to data collected by the
AGA through the PPDC is outside the
scope of the NPRM. However, PHMSA
will consider raising with other
members of the PPDC whether its
reporting protocols for MFFs should be
modified.
D. Monetary Threshold for Incident
Reporting (Section 191.3, New
Appendix A to Part 191)
1. PHMSA’s Proposal
On May 3, 1984, PHMSA’s
predecessor agency, the Research and
Special Programs Administration, added
a definition for an ‘‘incident’’ at
§ 191.3.37 The definition provides
criteria that requires operators to report
specific events to PHMSA. The 1984
definition of an incident consists of a
release of gas that, among other things,
results in estimated property damage of
$50,000 or more. That monetary
threshold includes losses to the operator
and third parties but excludes the cost
of any lost gas. Today, over 30 years
later, operators must still notify the
National Response Center (§ 191.5) and
submit an incident report to PHMSA
(§§ 191.9 and 191.15) for any release
that results in estimated property
damage to the operator or third parties
of $50,000 or more.
Multiple comments submitted in
response to the DOT Notification of
Regulatory Review addressed the
$50,000 monetary damage threshold for
reporting gas pipeline incidents. The
Associations, GPTC, and GPA
Midstream submitted comments
recommending an increase in the
monetary damage threshold for
reporting gas pipeline incidents. 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.38 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.
PHMSA proposed in the NPRM to
raise the reporting threshold for
incidents that result in property damage
to $122,000, consistent with inflation
since 1984. The property damage
criterion will continue to include losses
to the operator and others but exclude
the cost of lost gas. PHMSA did not
propose any changes to the other criteria
FR 18960.
analysis is based on the CPI for All Urban
Consumers (CPI–U) from the Bureau of Labor
Statistics, accessible at https://data.bls.gov/cgi-bin/
cpicalc.pl.
2219
in the § 191.3 definition of an incident.
The NPRM stated that PHMSA intended
to base any finalized version of this
provision on the price level at the time
of publication of a final rule. PHMSA
also requested 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 de facto annually-decreasing
threshold after inflation would provide
beneficial information on contributing
risk factors and incident trends.
The NPRM also stated that PHMSA
intends to 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:
Where Tn is the revised damage
threshold, Tp is the previous damage
threshold, CPIn is the average CPI–U for
the preceding 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 (FRA) implemented to
update the criteria for reporting
accidents/incidents at 49 CFR 225.19
and appendix B to part 225.39
2. Summary of Public Comments
Several commenters (including AGA
et al., AmeriGas, the Arkansas
Independent Producers and Royalty
Owners (AIPRO), GPA Midstream,
NPGA, Paiute, the GPTC and SPP)
expressed support for PHMSA’s
proposal to update the threshold for
property damage in the definition of an
incident to account for inflation. AGA,
API, APGA, GPA Midstream, and
INGAA reiterated their support for this
proposal in supplemental comments
submitted after the GPAC meeting. AGA
et al. also supported revising the initial
property damage threshold to reflect
inflation at the time of final rule
publication. AGA et al. stated that the
cost of repairing or remediating incident
damage in today’s environment is far
greater than it was in 1984, and that
even with the inflation adjustment,
more minor events will still be reported
37 49
38 This
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39 85 FR 79130 (Dec. 9, 2020) (updating FRA’s
monetary threshold for railroad incident reporting
requirements by way of annual notices published
on FRA’s website).
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as an incident than would have been in
1984. They asserted that this results in
a distorted view of pipeline safety
performance, since reportable incidents
are often used as a performance metric
for the natural gas industry. AGA et al.
also stated that the increase in the
reporting threshold will reduce the
number of calls made to the National
Response Center (NRC) for minor events
that are easily remediated by the
operator, and reduce the potential of
having to report minor incidents that
unnecessarily tie up resources of both
the producer and PHMSA.
FreedomWorks stated that adjusting the
threshold for inflation is simply good
housekeeping, adding that it should
have been indexed to inflation when the
threshold was originally established.
This commenter stated their support for
including this amendment in the
proposed rule while noting that
eventually eliminating the property
damage criterion entirely would be
ideal. Paiute and Southwest also
supported the proposed change, noting
that it would directly reduce the
regulatory burden on them. Southwest
further stated that they analyzed the
details of the § 191.3 reports their
company has made since 2010 where
the only reporting criteria met was
exceeding the $50,000 estimated
property damage threshold and
determined that only 9 percent of this
subset of reported incidents would have
met the revised proposed estimated
property damage threshold of $122,000.
TC Energy supported changing the
incident definition to adjust the amount
of monetary damage to align with
inflation, and recommended a monetary
damage threshold of $250,000, which
they stated would accurately reflect
repair costs for minor incidents. They
stated that while the proposed threshold
of $122,000 may take inflation into
account, it will continue to result in
several minor incidents being
considered reportable due to the cost to
respond based on labor, repair
materials, and permitting.
AGA et al. also supported updating
the reporting threshold every 2 years to
account for inflation, noting that
periodic updates will provide certainty
and avoid a repeat of the current
situation where the current threshold
does not account for over 3 decades of
inflation. AGA et al. further supported
implementing the biennial periodic
updates via notice on the PHMSA
website, stating that conducting biennial
rulemakings to update the threshold
seems unnecessarily burdensome for
both PHMSA and stakeholders. They
asserted that the current NPRM provides
adequate notice and opportunity for
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comment on the proposed method to
update the threshold periodically. They
recommended that PHMSA revise
§ 191.3 to clarify in the final rule the
agency’s intended process for
periodically updating the threshold.
FreedomWorks recommended that
PHMSA mandate a biennial update in
the final rule. NPGA agreed with
periodic modifications to the threshold,
suggesting annual updates by means of
a direct final rule published in the
Federal Register. TC Energy, on the
other hand, commented that biennial
updates may prove burdensome, but
supported incorporating whatever
process PHMSA settles on for
periodically updating the property
damage threshold into the PSR.
NAPSR suggested that PHMSA use
the language ‘‘$50,000 or more as
measured in 1984 dollars adjusted for
inflation,’’ which would prevent the
need to amend the PSR every year. They
further suggested that PHMSA could
announce the reporting threshold
annually as is done with random drug
testing rates, and civil penalties as
found in 49 CFR 190, or by simply
updating the incident report forms and
instructions every year to reflect the
recalculated reporting threshold.
However, NAPSR also noted that the
historical data collected by PHMSA
using the prior criteria may result in
skewed statistical incident results until
several years of collection using the new
formula, if adopted, is completed.
NAPSR suggested that PHMSA first
study the effects of changing the
reportable criteria dollar amount and
how they plan to reconcile any new data
to provide meaningful information to
the State programs and to the public.
They also suggested that PHMSA
consider how such data will relate to
any required cost benefit analysis
related to future pipeline safety
regulations and whether any change to
the dollar reporting criteria could affect
the ability to promulgate effective
regulations.
Two commenters opposed changing
the monetary threshold for incident
reporting from $50,000 to $122,000. PST
commented that PHMSA should be
seeking to obtain more information
about pipeline failures, not less. They
asserted that PHMSA can only make
regulatory decisions about design,
manufacture or operating conditions
that they know cause problems, and if
they are told about fewer problems, they
will not be able to determine whether
they need to regulate certain safety
issues. They further stated that if
PHMSA is determined to re-define the
term ‘‘incident,’’ it should undertake a
comprehensive look at that definition,
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and not merely adjust the property
damage criteria. They asserted that
making incremental, sequential
adjustments to the definition will
disrupt and frustrate trend analyses,
recommending that PHMSA identify,
analyze, and consider all potential
changes at once. They stated that
reducing the number of incidents
reported provides PHMSA less safety
data, and saves operators very little
money, while potentially misleading the
public about the improvement in the
number of reported incidents that occur
in future years. PST further stated that
PHMSA and the industry have all
committed to pursuing a goal of zero
incidents, and that PHMSA should not
facilitate that goal by defining reportable
incidents away.
Theresa Pugh Consulting also
opposed changing the monetary
threshold for incident reporting. They
stated that since 1984, the United States
has become more densely populated
such that natural gas pipelines and
compressor stations could cause ‘‘partial
damage to $50,000 in property that
merits reporting to PHMSA.’’ While the
commenter recognized there is a
regulatory cost associated with this
reporting, they asserted that it is the cost
of doing business in a critical, necessary
and dangerous business. The
commenter asserted that property
damage is still important if it is valued
at greater than $50,000, noting that a
damaged or lost $50,000 structure or
capital equipment can be a major
business investment even if it might
seem less significant to a multimilliondollar pipeline project.
One commenter recommended that
while PHMSA is addressing the
monetary damage limits in the
definition of incident in § 191.3, it
should also address the issue of how
operators determine what constitutes a
‘‘significant event’’ under item (iii) of
the definition. The commenter stated
that the failure of an operator to
evaluate their system and define what is
significant for their personnel leads to
confusion and can cause delayed
reporting, or even non-reporting, of
incidents.
The GPAC voted 11–2 in favor of
PHMSA’s proposed amendment to the
definition of an incident provided that
PHMSA adopted an updated property
damage criterion commensurate with
the CPI at the time of final rule
publication. The GPAC further
recommended regular administrative
updates using procedures like those
proposed by the Federal Railroad
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Administration for part 225.40 Two
members voted against the proposed
amendments.
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3. PHMSA Response
PHMSA agrees with comments
supporting the adoption of an up-to-date
property damage threshold in the final
rule. The most recent complete calendar
year is 2019. Therefore, the property
damage criterion following the effective
date of this final rule is set to $122,000
consistent with CPI inflation between
1984 and 2019.
PHMSA also agrees that it is
appropriate to perform updates in the
future to account for inflation via a preestablished formula. To this end,
PHMSA has incorporated the formula
described in the preamble to the NPRM
into a new appendix A to part 191. In
the future, annual updates to the
property damage criterion will be
calculated based on this formula and
posted to PHMSA’s website such that
they will become effective July 1 of each
year. The revision to the incident
definition has no direct safety impact,
better reflects the intent of the original
property damage criterion, and only
impacts reports of releases without
significant safety or environmental
consequences. Whether a release is
classified as an incident has no effect on
an operator’s regulatory obligation to
repair hazardous leaks promptly
(§ 192.703) and establish and follow
procedures for responding to gas
pipeline emergencies (§ 192.615) and
investigating failures (§ 192.617). None
of the repair criteria in part 192 depend
on whether a leak or defect results in a
reportable incident.
PHMSA disagrees that changing the
property damage criterion adversely
affects trend analysis. In fact, a static
property damage threshold decreases in
real value time. PHMSA already
addresses this issue when performing
and presenting trend analysis of
‘‘significant’’ incidents. PHMSA’s
analyses of ‘‘serious incidents’’ include
only incidents that result in reported
deaths or injuries and are not affected
by inflation because the ‘‘serious’’
threshold criteria do not include a
property damage criterion. In contrast,
PHMSA uses the term ‘‘significant
incidents’’ to mean those with (1)
reported deaths or injuries, or (2)
$50,000 or more in total costs, measured
in 1984 dollars. Additional information
on these trend analyses is available on
PHMSA’s web pages for National
40 As noted earlier, FRA finalized that proposal in
December 2020.
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Pipeline Performance Measures 41 and
Pipeline Incidents, 20 Year Trends.42
PHMSA currently uses inflation data
published by the Bureau of Economic
Analysis, the Government Printing
Office, and the Energy Information
Administration in calculating inflation
adjustments for ‘‘significant incidents.’’
Following the effective date of the final
rule, PHMSA will no longer employ
those tools in adjusting the ‘‘significant
incident’’ property damage threshold for
inflation, but will instead use the
Bureau of Labor Statistics CPI.
Regarding comments from Theresa
Pugh Consulting, PHMSA did not
propose to create a new incident
definition criterion for releases or
pressure drops that disrupt supply to
downstream consumers and others
indirectly impacted by gas pipeline
failures, therefore these suggestions are
outside the scope of the NPRM. PHMSA
acknowledges that property damage
exceeding $50,000 can have a
significant effect on third parties
affected by the release and notes that it
understands that some States have
lower incident reporting thresholds to
address just that concern.
PHMSA disagrees with comments
from TC Energy and FreedomWorks
suggesting more radical changes to the
property damage criterion. PHMSA does
not believe that an arbitrarily higher
damage threshold or eliminating the
reporting entirely would be appropriate.
Even if repair costs may have risen
faster than inflation, TC Energy has not
provided a convincing rationale for why
$250,000 represents current repair costs
for incidents across the industry. In
addition, while a simple inflation
adjustment is consistent with how
PHMSA currently uses incident data, a
significant change to the incident
definition beyond a simple inflation
adjustment would affect the ability of
PHMSA and other data users to track
incident trends as alluded to by other
commenters.
PHMSA is deferring for a future
rulemaking consideration of the other
amendments to the incident reporting
criteria at § 191.3 that were suggested by
comments received in the rulemaking
docket. Further evaluation of those
proposals would be helpful.
Corrosion Control
Virtually all hazardous liquid and
most natural gas transmission pipelines
in service today are made of steel.
Metallic pipelines, when not protected,
41 https://www.phmsa.dot.gov/data-andstatistics/pipeline/national-pipeline-performancemeasures.
42 https://www.phmsa.dot.gov/data-andstatistics/pipeline/pipeline-incident-20-year-trends.
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react with the surrounding environment
and can deteriorate over time due to
corrosion. Under certain conditions,
unprotected metal can corrode, causing
gas leaks that can threaten public safety.
To guard against this, subpart I of part
192 of 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 proposed two
amendments related to corrosion
control: first, to clarify that cathodic
protection rectifiers can be inspected
remotely and second, to revise the
requirements for assessing atmospheric
corrosion on distribution service
pipelines.
E. External Corrosion Control:
Monitoring (Section 192.465)
1. PHMSA’s Proposal
In the NPRM, PHMSA proposed to
revise § 192.465(b), ‘‘External corrosion
control: Monitoring,’’ to clarify that
operators may monitor rectifier stations
remotely. Rectifiers are devices that
direct an electrical current on a pipeline
to prevent external corrosion. Section
192.465(b) requires inspection of
rectifiers on gas pipelines at intervals
not exceeding two and a half months, 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 proposed to
revise § 192.465(b) to clarify that
operators may inspect rectifier stations
directly onsite or by way of remote
monitoring technologies. The NPRM
also clarified that, at a minimum, such
an inspection consists of recording
amperage and voltage measurements.
PHMSA also proposed to require
operators physically inspect rectifier
stations that are being monitored
remotely whenever they conduct a
cathodic protection test pursuant to
§ 192.465(a). For pipelines, other than
separately protected service lines or
separately protected short sections of
transmission lines or mains,
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§ 192.465(a) requires physical
inspection once each calendar year.
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2. Summary of Public Comments
Several commenters (including AGA
et al. and TC Energy) supported
PHMSA’s proposal allowing remote
inspection of impressed current
cathodic protection sources. PST stated
that they do not oppose allowing the
remote inspection of rectifier stations
provided the proposed addition of a
requirement that remotely inspected
rectifier stations be physically inspected
once a year is retained. AGA et al. and
TC Energy recommended that PHMSA
clarify that operators must physically
inspect remotely inspected rectifiers at
the cathodic protection test frequency
required in § 192.465(a) and that the
rectifier inspection need not necessarily
occur at the exact same time as the
cathodic protection testing. They
indicated that the currently-proposed
wording of § 192.465(b)(2) could be
interpreted to require a redundant
physical inspection of the same rectifier
every time each of the pipeline
segments influenced by that rectifier is
tested, or even multiple times per
segment if the testing occurs over
multiple days. AGA et al. suggested
specific revisions to the proposed
§ 192.465(b)(2).
Four commenters (NPGA, AmeriGas,
SPP, and a private citizen) suggested
changes to the proposed physical
inspection interval. They commented
that if rectifier inspection can be done
remotely and it is performed at intervals
no greater than two and a half months,
PHMSA should consider allowing an
operator to extend the physical
inspection interval for rectifiers on
distribution lines beyond once per year,
provided the results of remote
inspections are properly documented.
The commenters claimed that
documentation of the results will
indicate if, or when, physical inspection
of the rectifiers is needed, but did not
provide a specific timeline.
One private citizen expressed
opposition to the proposed amendment.
The commenter requested more frequent
inspection of rectifiers, and suggested
that the proposed change does not align
with industry policies. The commenter
noted that corrosion is one of the main
causes of pipeline failures and
suggested that a physical inspection is
already required within the rectifier
checks required in § 192.465(b). Based
on this interpretation of § 192.465(b),
the commenter argued that PHMSA was
effectively extending the required
interval to perform physical inspections
of rectifiers and other devices from six
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times a calendar year to once per
calendar year.
The GPAC voted unanimously in
favor of PHMSA’s proposal with respect
to external corrosion monitoring
provided that PHMSA clarify that the
physical inspection of a remotely
inspected rectifier is expected to occur
annually rather than exactly when
cathodic protection surveys occur.
3. PHMSA Response
PHMSA has adopted the proposed
amendments to § 192.465 with minor
revisions to the physical inspection
requirements. The amendments clarify
that remote inspection is permitted by
the PSR. PHMSA’s corrosion
enforcement guidance contains
numerous interpretations clarifying that
§ 192.465(b) does not specify a
particular technology, but rather permits
any technology that provides reliable
data, including ‘‘electronic data
collection and the subsequent broadcast
of this data to operators.’’ 43 PHMSA
expects that the data obtained from
remote inspection of rectifiers will not
adversely affect the quality and quantity
of information available on their
function, and does not expect the PSR
amendments to § 192.465(b) to have an
adverse impact on safety.
PHMSA agrees with comments to
specify that the physical inspection
should occur annually rather than
exactly when a cathodic protection
survey is performed under § 192.456(a).
This change better reflects PHMSA’s
intent for operators to perform an
annual physical inspection. This change
has no impact on the intended
frequency of inspections, but provides
more flexibility to operators and avoids
situations where inspections would
have been required more frequently
than intended.
PHMSA disagrees with the comment
that § 192.465(b) already requires
physical inspection during each rectifier
inspection and that PHMSA’s proposal
would lengthen the intervals for
physical inspection. While some
operators may conduct a physical
inspection with each of their rectifier
checks, § 192.465(b) currently does not
require them to do so.
PHMSA does not adopt a longer
physical inspection interval for
distribution pipelines as suggested in
comments from LPG distribution system
operators and suppliers. These
43 See, e.g., PHMSA Pipeline Enforcement
Guidance: Part 192 Corrosion Enforcement
Guidance (2015), available at https://
www.phmsa.dot.gov/sites/phmsa.dot.gov/files/
docs/Corrosion_Enforcement_Guidance_Part192_
12_7_2015.pdf (citing PHMSA Interpretation #PI–
ZZ–080 (Aug. 19, 1991)).
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comments did not present an alternative
timeline that would have been
appropriate for distribution operators,
and PHMSA believes that operators
have ample opportunities to perform an
annual physical inspection during other
inspection activities.
F. Atmospheric Corrosion: Monitoring
(Sections 192.481, 192.491, 192.1007,
192.1015)
1. PHMSA’s Proposal
PHMSA proposed to revise § 192.481
to establish a separate atmospheric
corrosion inspection interval for gas
distribution service pipelines.
Currently, all onshore gas pipelines that
are exposed to the atmosphere must be
inspected for atmospheric corrosion
once every 3 years, with intervals not to
exceed 39 months. This includes
facilities that are installed aboveground,
in underground vaults, or inside
buildings. PHMSA proposed a
maximum inspection interval for service
lines of once every 5 calendar years,
with intervals not to exceed 63 months,
unless atmospheric corrosion was
identified on the last inspection. If an
operator identifies atmospheric
corrosion on a service line during an
inspection, then the required interval
for the subsequent inspection would
remain once every 3 years, with
intervals not to exceed 39 months. If no
atmospheric corrosion is identified on a
subsequent inspection, then operators
would be permitted to return to using
the 5-year inspection interval. PHMSA
also proposed to revise §§ 192.1007(b)
and 192.1015(b)(2) to clarify that
consideration of corrosion risks under
DIMP explicitly includes atmospheric
corrosion. PHMSA did not propose any
changes to the inspection requirement
for other facilities, including
distribution mains. PHMSA’s proposed
change was informed by its
understanding that there has not been a
history of incidents caused by
atmospheric corrosion on distribution
service lines since at least 1986 44 and
therefore does not anticipate a decrease
in safety from these PSR revisions.
2. Summary of Public Comments
Several commenters (including
Oleksa and Associates, FreedomWorks,
and AGA et al.) expressed support for
establishing a separate atmospheric
corrosion inspection interval for gas
distribution service pipelines.
FreedomWorks stated that the changes
would reduce the costs for both
44 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.
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operators and inspectors. AGA et al.
supported revising § 192.481 to align the
inspections intervals for atmospheric
corrosion with those of leak surveys
required by § 192.723. AGA et al.
asserted that the NPRM’s proposed PSR
revisions would reduce regulatory
burdens while enhancing pipeline
safety in that the resources saved from
such alignment could be reallocated to
other pipeline safety activities and asset
improvement projects.
Some commenters (including SPP,
NPGA, and AmeriGas) supported the
extension of the inspection interval to 5
years for service lines, but
recommended that if documented action
were taken to remediate the coating as
specified in § 192.479, then the
inspection interval should remain at 5
years. The commenters stated that there
is not a need to drop down to 3 years
if remediation occurs.
AGA et al. and GPTC agreed that the
existing 3-year interval when corrosion
is identified is not necessary to manage
atmospheric corrosion risks if the
service line is replaced or remediated,
especially considering existing DIMP
requirements, and the proposed
requirement to consider atmospheric
corrosion risks under DIMP included in
the NPRM. They agreed with PHMSA’s
assessment that there is expectation for
operators of service lines in highcorrosion environments to consider
atmospheric corrosion in their
evaluation of risks under DIMP and
conduct atmospheric corrosion
inspections more frequently than the
minimum requirements in § 192.481.
AGA et al., therefore, recommended a
prescriptive remediation requirement in
lieu of a shortened inspection cycle.
They stated that by remediating through
recoating or replacement, operators can
continue to keep all service pipelines on
a 5-year inspection cycle. They
provided specific regulatory text
revisions in their comment. AGA et al.
also requested that PHMSA remove the
word ‘‘evaluate’’ from § 192.481(a).
They noted that PHMSA did not
provide justification for adding the
requirement to evaluate under
§ 192.481(a). INGAA, AGA, APGA, API,
and GPA Midstream submitted
supplemental comments after the GPAC
meeting arguing that the 3-year
inspection interval when corrosion has
been identified would negate any cost
savings from the proposed revisions to
§ 192.481.
Similarly, NAPSR commented that if
atmospheric corrosion is found that
corrosion should be remediated rather
than be subject to a shorter inspection
interval. NAPSR argued this would be
more reliable from a safety perspective
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than establishing a shorter inspection
interval. Alternatively, NAPSR
recommended that PHMSA consider
revising both §§ 192.481 and 192.723 to
require a shorter, perhaps 3- or 4-year,
residential leak survey requirement and
require that operators complete their
atmospheric corrosion survey at the
same interval. NAPSR argued this
would provide for greater safety
regarding leak surveys, while making it
more practical to combine compliance
intervals for two operation and
maintenance categories. NAPSR further
commented that any change to the
atmospheric corrosion control
inspection interval should be
accompanied by a change to the record
keeping requirements in § 192.491.
NAPSR recommended that operators be
required to retain records for the
previous two inspection cycles.
A2LA recommended that PHMSA
implement a risk-based approach to
determine permissible inspection
intervals rather than the 3-year or 5-year
intervals described in the NPRM. A2LA
stated the risk-based approach can then
account for considerations such as the
age of the pipeline, climate, geologic
conditions, use, and maintenance
history. They agreed with the proposed
rulemaking that the maximum
inspection interval for service lines
should be 5 calendar years, with
intervals not to exceed 63 months.
Two gas distribution operators and an
industry organization commented that it
is unclear whether, if corrosion was
identified, a 3-year inspection interval
would be required for the entirety of the
distribution system or just at the
location or address where the corrosion
exists. They recommended that PHMSA
consider clarifying that the 3-year
inspection interval applies to ‘‘only
such areas as corrosion was identified.’’
PST commented that they are unable
to support changes in monitoring
frequency because corrosion continues
to cause many incidents. They
commented that corrosion-related
incidents indicate that more
prescriptive corrosion monitoring
regulations might be warranted.
However, they noted that they do not
strongly oppose this change, as PHMSA
indicates it has no recent records of
incidents caused by atmospheric
corrosion on distribution service lines.
The GPAC voted twice on this
amendment. First, the GPAC voted 7–5
in favor of the proposed rule with
respect to atmospheric corrosion,
provided that PHMSA amend
§ 192.491(c) to clarify that an operator
must retain records of the last two
atmospheric corrosion inspections to
use the 5-year inspection interval. This
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vote recommended retaining the
proposed requirement to inspect lines
where corrosion was identified on the
last inspection within 3-years, and did
not incorporate the remediation
alternative to a 3-year inspection that
was suggested by some commenters.
Second, the GPAC voted 10–2 in favor
of the proposed rule with respect to
atmospheric corrosion if PHMSA
adopted a 5-year cycle rather than a 3year cycle when atmospheric corrosion
is found, provided that the operator has
evaluated and remediated the facility
and there is no evidence of systemic
atmospheric corrosion due to the
environment or similar factors.
3. PHMSA Response
After considering the public
comments and the GPAC
recommendations, the final rule adopts
the amendment with respect to
atmospheric corrosion inspection of
service lines as proposed with minor
clarification to recordkeeping
requirements in § 192.491(c). Alignment
of atmospheric corrosion inspection
intervals with those for leakage surveys
in § 192.723 will allow greater
scheduling flexibility for operators and
decreased costs arising from less
frequent atmospheric inspections. As
stated in the NPRM, PHSMA is unaware
of any pipeline incidents arising from
atmospheric corrosion on a service line.
In addition, 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, 2019.45 PHMSA
has not observed an increase in leaks or
incidents from this and other State
waivers. For these reasons, PHMSA
finds that a longer atmospheric
corrosion inspection interval is
supported in areas with low observed
atmospheric corrosion risk.
The final rule applies the new 5-year
inspection interval to distribution
service lines. Although PHMSA
acknowledges that operators have
reported atmospheric corrosion
incidents on distribution mains,
PHMSA understands the design and
operational characteristics of service
lines make them less susceptible to
atmospheric corrosion induced failure.
Compared to distribution mains, service
lines tend to have smaller diameters,
45 Additional information on these historical
examples is available in the rulemaking docket and
the docket for the South Dakota State waiver
(PHMSA–2019–0052).
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have lower flow rates, and are
constructed with thicker walls relative
to the outside diameter of the pipeline.
They can therefore endure more
atmospheric corrosion induced metal
loss before operating stresses would
compromise pipeline integrity. In
addition, aboveground distribution
facilities other than service lines (i.e.
mains) must be inspected more
frequently under part 192, providing
ample opportunity for operators 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 is necessary to ensure that
distribution facilities are adequately
inspected for atmospheric corrosion
sufficiently frequently so that it can be
remediated before it leads to a failure.
An open-ended reference to DIMP, as
suggested in the Associations’ comment
on the DOT Notification of Regulatory
Reform, would not provide this
safeguard. The proposed maximum
interval of 5 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 under § 192.723(b)(2)
concurrently. PHMSA was not
persuaded that there is significant
benefit to allowing atmospheric
corrosion inspection intervals longer
than the maximum leakage survey
interval as described by some
commenters. Inspecting the
aboveground portion of a service line is
not a significant additional burden
when operators are already walking the
service line to perform leakage surveys.
The proposed revisions to
§§ 192.1007(b) and 192.1015(b)(2) to
evaluate atmospheric corrosion risks
under DIMP and the shorter inspection
interval for pipelines with observed
corrosion will also ensure that operators
of service pipelines with atmospheric
corrosion threats take appropriate action
to maintain the integrity of those
pipelines.
Those revisions clarify that
consideration of corrosion under DIMP
must include 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
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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 to take mitigative
action, such as more frequent inspection
or maintenance activities, as part of
their DIMPs and accurately and
completely document such actions.
The final rule does not adopt
proposals (by commenters and GPAC)
for remediation as an alternative to the
NPRM’s approach of shorter inspection
intervals following observation of
atmospheric corrosion. While
commenters suggested a ‘‘prescriptive’’
remediation requirement, the regulatory
language suggested in comments from
the Associations neither defines what
constitutes an adequate repair of
atmospheric corrosion (other than
replacement), nor how their proposal
differs from existing part 192
requirements for remediation and repair
of atmospheric corrosion and other
conditions that could reduce the
pipeline’s integrity. Based on the GPAC
discussion, remediation as discussed by
commenters consists of removing
corrosion with a wire brush and
repainting the facility pursuant to the
existing § 192.479 requirements. These
actions are already required by existing
§ 192.481, through reference to
§ 192.479, which requires an operator to
clean and suitably coat pipelines
exposed to the atmosphere, and
§ 192.703 requires operators to replace,
repair, or remove pipeline segments that
become unsafe and promptly repair all
hazardous leaks. In addition, finding
atmospheric corrosion is an indication
that a corrosive environment may exist.
Inspection of such service lines within
3 years protects against this risk. Any
remediation alternative requires careful
consideration of what constitutes
adequate remediation because corrosion
has already been identified on the
pipeline.
PHMSA also declines to NAPSR’s
alternative approach of aligning
atmospheric corrosion inspection and
leaky survey frequencies by revising
§ 192.723 to require more frequent leak
surveys. PHMSA is unaware of record
evidence supporting a need for
shortened leak survey intervals, even as
PHMSA finds that the absence of
incidents resulting from atmospheric
corrosion support extending the
inspection interval as provided by this
final rule. In addition, more frequent
leak inspection surveys under § 192.723
will likely entail significant operator
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costs without record evidence of a
corresponding safety benefit.
PHMSA is not persuaded by
arguments raised by GPAC members
and comments submitted after the
GPAC meeting that reverting to a 3-year
inspection interval for a distribution
service line after atmospheric corrosion
has been observed makes the
amendment technically impracticable or
economically infeasible. A 3-year
inspection interval is the current
requirement that has been in place for
decades. Based on cost estimates
provided by industry comments,
PHMSA determined in the RIA that
significant cost savings for the NPRM’s
proposed revisions to atmospheric
corrosion monitoring requirements stem
from reduced inspection frequency in
the absence of observed atmospheric
corrosion. If, however, the operator
observes atmospheric corrosion and
remediates it as required in part 192,
then an operator should rarely observe
atmospheric corrosion during the 3-year
inspection following remediation, after
which they may return to a 5-year
inspection interval and continue to
enjoy cost savings into the future. An
operator can easily keep atmospheric
corrosion and leakage surveys in sync
by performing the next leakage survey
within 3 years and then continuing
every 5 years on subsequent inspections
provided no corrosion is identified in
the future. If the operator is unable to
use the 5-year inspection interval
effectively because they repeatedly
observe atmospheric corrosion, then the
rule is working as intended to protect
the public in areas with high rates of
atmospheric corrosion.
Finally, consistent with the
recommendations of the GPAC and
comments received in the rulemaking
docket, the final rule revises the
corrosion control recordkeeping
requirements in § 192.491(c) to clarify
that an operator must retain records of
the two most recent atmospheric
corrosion inspections in order to use the
5-year inspection interval for facility
distribution service line. This change
ensures that operators can provide
adequate documentation that corrosion
was not identified on a service line that
is being inspected on a 5-year interval.
ASTM and ASME Standards
Incorporated by Reference
G. Plastic Pipe (Sections 192.7, 192.121,
192.281, 192.285, Appendix B to Part
192)
1. PHMSA’s Proposal
The NPRM proposed to update
§§ 192.7, 192.121 and appendix B to
part 192 to incorporate by reference the
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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).46 ASTM D2513 specifies the
design requirements of Polyethylene
(PE) pipe and fittings. These
improvements include more specific
testing requirements for measuring
resistance to ultraviolet exposure and
clarifying the applicability of the
document to all PE fuel gas piping.
Consistent with the updated ASTM
standard, PHMSA also proposed to raise
the diameter limit for using a design
factor of 0.4 on PE pipe from 12 inches
to 24 inches and add corresponding
entries for those sizes to the PE
minimum wall thickness table at
§ 192.121(c)(2)(iv). PPI, representing
manufacturers of plastic pipe and
components, and a citizen commenter
submitted comments in response to the
DOT Notification of Regulatory Review
addressing this issue. PHMSA reviewed
ASTM D2513–18a 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. PHMSA also determined that
the other safety improvements since the
2012ae1 edition merit incorporation by
reference in the PSR as their
incorporation would not have an
adverse impact on safety, while
improving regulatory clarity and
alignment with consensus industry
practices.
Currently, PHMSA incorporates by
reference ASTM D2513–12ae1 into item
I, appendix B to part 192. While Table
2 (Outside Diameters and Tolerances for
Plastic Pipe) of ASTM D2513–12ae1
includes outside diameter specifications
for pipe sizes up to 24-inch nominal
diameter, Table 4 (Wall Thicknesses and
Tolerances for Plastic Pipe) only
includes wall thickness specifications
for pipe sizes up to 12-inch nominal
diameter. Because ASTM D2513 is the
listed specification for PE plastic pipe in
appendix B to part 192, and
§ 192.121(c)(2)(iv) mirrored the
published wall thicknesses and
tolerances in Table 4 of ASTM D2513–
12ae, part 192 does not currently allow
use of a 0.4 design factor for PE pipe
diameters above 12 inches. Now that the
ASTM D2513–18a includes in its Table
4 wall thicknesses for diameters through
24 inches, the corresponding table in
§ 192.121(c)(2)(iv) can be updated as
well.
In the NPRM, PHMSA also proposed
to modify requirements for joining
procedures in §§ 192.281 and 192.285 to
allow operators additional flexibility
when developing such procedures and
to improve safety. Specifically, PHMSA
proposed to incorporate by reference the
2019 edition of ASTM F2620, ‘‘Standard
Practice for Heat Fusion Joining of
Polyethylene Pipe and Fittings’’ and
revise §§ 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 47 in response to the final rule
entitled ‘‘Pipeline Safety: Plastic Pipe
Rule’’ issued on November 20, 2018.48
In the Plastic Pipe Rule, PHMSA
amended §§ 192.281 and 192.285 to
require that 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 contains 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 §§ 192.281
and 192.285 could be interpreted to
require operators to requalify safe
procedures that had been qualified in
the past in accordance with § 192.283.
AGA commented that many operators
use heat fusion procedures published by
PPI, such as PPI TR–33 and PPI TR–41.
While PHMSA noted in the preamble of
the Plastic Pipe Rule that PHMSA
would find a joining method acceptable
if ‘‘an operator can demonstrate the
differences are sound and provide
equivalent or better safety compared to
ASTM F2620,’’ AGA raised concerns
that the regulatory text itself does not
necessarily provide this flexibility, and
46 ASTM International, ASTM D2513–18a—
‘‘Standard Specification for Polyethylene (PE) Gas
Pressure Pipe, Tubing, and Fittings’’ (Aug. 1, 2018).
47 Docket Number PHMSA–2019–0200. https://
www.regulations.gov/docket?D=PHMSA-2019-0200.
48 83 FR 58694.
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suggested PHMSA explicitly allow the
use of other qualified procedures, such
as PPI TR–33 and PPI TR–41.
In the NPRM, PHMSA proposed to
revise §§ 192.281 and 192.285 to
achieve the flexibility sought in the
Plastic Pipe Rule. Specifically, PHMSA
proposed to revise § 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 the internal
and external loads, and have been
validated by formal testing in
accordance with § 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 Rule, for operators to
demonstrate compliance, PHMSA
expects operators to document the
differences from ASTM F2620 and
demonstrate how the alternate
procedures provide an equivalent or
superior level of safety. Similarly,
PHMSA proposed to revise
§ 192.285(b)(2)(i) to allow other written
procedures that have been proven by
test or experience to produce strong,
gastight joints. If the operator’s
procedures are found to be lacking in
any way—such as changes to surface
preparation, heating temperatures,
fusion pressures, cooling times that lack
a technical justification demonstrating
an equivalent or superior level of
safety—they would be unacceptable and
would not comply with the PSR.
PHMSA also proposed to incorporate
by reference the 2019 edition of ASTM
F2620. The updated edition of the
standard clarifies the relationship
between ASTM F2620 and the certain
PPI documents referenced in AGA’s
petition within a new Note 1 in section
1.2. That Note identifies parameters and
procedures in F2620 that were
developed and validated using PPI TR–
33 (butt fusion) PPI TR–41 (saddle
fusion), thereby facilitating operators’
ability to referencing those PPI
documents in developing their technical
justification for use of an alternative
procedures under § 192.285(b)(2)(i). In
addition, the 2019 edition of ASTM
F2620 includes several incremental
improvements on the 2012 edition to
safety and editorial clarity. These
improvements include a new section 6.4
that requires additional precautions
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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
§ 192.285. Further, 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 are expected to
reduce potential issues caused by
inadequate surface preparation, which
has been a factor in past incidents.49
PHMSA also proposed to clarify
§ 192.285 in response to questions
PHMSA has received following
publication of the Plastic Pipe Rule.
First, PHMSA proposed to remove
references to testing in relation to ASTM
F2620 to clarify that only visual
inspection in accordance with that
standard is required. Several
stakeholders asked what specific testing
is required in ASTM F2620. While
ASTM F2620 describes testing in a nonmandatory appendix of the standard, it
does not require specific testing.
Clarifying that operators must visually
inspect specimen joints in accordance
with ASTM F2620 avoids confusion
about whether non-mandatory testing
described in ASTM F2620 is required by
§ 192.285(b)(2)(i). PHMSA also
proposed to clarify that testing in
accordance with § 192.283(a) is still
required for PE heat fusion joints. The
current text could be read to require
only visual inspection in accordance
with ASTM F2620 for PE heat fusion
joints. The changes in this rule clarify
PHMSA’s intent to require that such
joints be tested in accordance with
§ 192.283(a) and visually inspected in
accordance with ASTM F2620.
Additional testing in accordance with
the appendix of ASTM F2620 is
optional.
In addition to the matters raised
above, PHMSA proposed correcting
amendments to address the following:
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Design Pressure for Plastic Pipe
In § 192.121(a), PHMSA proposed the
words ‘‘design formula’’ be replaced
with the words ‘‘design pressure,’’
which is more accurate.
49 National Transportation Safety Board, ‘‘Safety
Through Reliable Fusion Joints,’’ SA–047 (June
2015), https://www.ntsb.gov/safety/safety-alerts/
Documents/SA_047.pdf.
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Minimum Wall Thickness for 1″ CTS
Pipe
In the minimum wall thickness tables
for PE (§ 192.121(c)(2)(iv)), polyamide
11 (PA–11) (§ 192.121(d)(2)(iv)), and
polyamide 12 (PA–12) (§ 192.121(e)(4))
pipe, PHMSA proposed that 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, most closely
corresponds to SDR 11, 1″ CTS pipe in
the standards incorporated by reference
for the design of PE (ASTM D2513), PA–
11 (ASTM F2945),50 and PA–12 (ASTM
F2785) 51 plastic pipe and fittings.
Qualifying Joining Procedures
In § 192.283(a)(3), ‘‘no more than 25%
elongation’’ is corrected to read ‘‘no less
than 25% elongation.’’ PHMSA
proposed to clarify that the test required
by this section is a tensile test. Tensile
testing is a measure of a material’s
resistance to pulling forces. The
revisions to § 192.283(a)(3) made in the
Plastic Pipe Rule inadvertently removed
the word ‘‘tensile,’’ though tensile
strength was still alluded to implicitly
because elongation is a measure of
tensile strength. Reinserting the word
tensile clarifies this relationship.
Dates
In § 192.121(c)(2) and (e), PHMSA
proposed to clarify that PE pipe and
PA–12 pipe respectively produced on or
after January 22, 2019 may use a DF of
0.40 rather than 0.32, subject to
applicable restrictions in those
paragraphs.
Corrections to 192.7
PHMSA proposed editorial
amendments to § 192.7(a) to meet
incorporation by reference requirements
of the Office of the Federal Register and
a revision to update the address for API.
2. Summary of Public Comments
ASTM D2513 and PE Pipe Diameter
Several commenters provided their
support, with no additional comments,
for the proposed amendments in the
NPRM.
AIPRO submitted comments
supporting the incorporation by
reference of the 2018a edition of ASTM
D2513 and conforming revisions to
§ 192.121. Similarly, PPI stated their
support to increase the allowable
50 ASTM F2945–12a ‘‘Standard Specification for
Polyamide 11 Gas Pressure Pipe, Tubing, and
Fittings’’ (Nov. 27, 2012).
51 ASTM F2785–12, ‘‘Standard Specification for
Polyamide 12 Gas Pressure Pipe, Tubing, and
Fittings’’ (Aug. 1, 2012).
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dimensions for PE pipe using a 0.40
design factor up through 24 inches
along with the corresponding minimum
wall thicknesses in Table 1 to paragraph
§ 192.121(c)(2)(iv). PPI stated that the
revisions are consistent with
dimensions provided in ASTM D2513–
18a and enables the increased use of
larger diameter PE in gas distribution,
transmission, and gathering systems.
PPI provided suggested regulatory text
revisions for § 192.121(a) to permit an
operator to allow an operator to operate
a plastic pipe at a temperature up to
180 °F, provided that the hydrostatic
design basis (HDB) is established at that
temperature. PPI noted that a survey of
AGA members indicated that local
distribution companies desire to use
plastic pipe at higher operating
temperatures providing them with more
application options, and that use of
these higher performance plastic
materials results in increased long-term
performance of the piping system and a
safer gas system.
GPA Midstream supported
incorporating by reference updated
editions of standards and believes that
the latest editions should be adopted
wherever possible. GPA Midstream
stated that relying on obsolete or
outdated editions of IBR standards
creates unnecessary compliance
burdens, discourages innovation, and
adversely affects the standards
development process. GPA Midstream
noted that a significant number of the
IBR standards have undergone multiple
revisions without being updated to a
newer or more recent edition. GPA
Midstream requested that PHMSA place
a renewed emphasis on the timeliness of
the incorporation by reference process,
particularly in cases where a prior
edition of a standard is already
incorporated by reference. In such cases,
PHMSA should commit to adopting the
latest edition of the standard or
providing an explanation for not doing
so within 1 year of publication.
ASTM F2620 and Joining Requirements
AGA et al. supported the changes
proposed to §§ 192.281 and 192.285.
They commented that the proposed
revisions in the NPRM aligned with
AGA’s petition for reconsideration of
the Plastic Pipe Rule, and allow
operators to use alternate procedures to
join PE which are equivalent or more
stringent than the heat fusion procedure
detailed in the 2012 edition of ASTM
F2620.
PPI supported PHMSA’s proposed
revision to §§ 192.281(c) and 192.285
providing for alternative written heat
fusion procedures that provide an
equivalent or superior level of safety.
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PPI also suggested incorporating PPI–
TR–33, ‘‘Generic Butt Fusion Joining
Procedure for Field Joining
Polyethylene Pipe’’ and TR–41,
‘‘Generic Saddle Fusion Joining
Procedure for Polyethylene Gas Piping’’
into § 192.281(c) in addition to ASTM
F2620. PPI explained that these
additions would help clarify the
language and account for proven
procedures that have been successfully
used in industry for many years. A2LA
suggested that PHMSA also incorporate
by reference ISO/IEC 17025, ‘‘General
Requirements for the Competence of
Testing and Calibration Laboratories’’
and require alternative written
procedures be validated by laboratories
certified in accordance with that
document. A2LA commented that ISO/
IEC 17025 recommends that a testing
laboratory uses consensus methods and
has procedures for the selection of
methods, and verify that a testing
laboratory can properly perform
methods by ensuring that it can achieve
the required performance and maintain
records of the verification. Regarding
PHMSA expecting operators to
document the differences from ASTM
F2620 and demonstrate how the
alternate procedures provide an
equivalent or superior level of safety,
A2LA recommended that the
organizations conducting the
inspections and testing be accredited, in
accordance with the relevant ISO/IEC
standards include requirements for
impartiality.
Southwest Gas Corporation
(Southwest) raised concerns with the
addition of the language ‘‘or superior’’
in the proposed language of both
§§ 192.281 and 192.285. Southwest
believes that this language ‘‘or superior’’
implies an increased performance
standard not defined in either ASTM
F2620 or part 192. Southwest requested
that PHMSA consider removing the
language ‘‘or superior’’ from the
proposed revisions to both § 192.281(c)
and § 192.285(b)(2)(i) and provided its
preferred regulatory text.
1-Inch CTS Pipe
The Associations and NAPSR
commented that operators commonly
use 1-inch CTS pipe with a wall
thickness of 0.099 inches, rather than
0.101 inches in the proposed rule. Both
wall thickness specifications are listed
as options in Table 3 of ASTM D2513.
NAPSR requested clarification of
whether operators are required to use a
design factor of 0.32 for PE pipe with a
minimum wall thickness of 0.099-inch,
and if thicker pipe is required to use a
0.40 design factor. The Associations
raised concerns about the impact to
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operators and manufacturers who have
an inventory of 0.099-inch wall
thickness PE pipe and suggested that
PHMSA correct the proposed
amendments to the minimum wall
thickness table at § 192.121(c)(2)(iv) to
reference 0.099-inch thick, 1-inch CTS
pipe that is commonly in use.
Qualifying Joining Procedures
PPI supported correcting
§ 192.283(a)(3), and allowing visual
inspection in accordance with
established written procedures in
§ 192.285(b)(2)(i).
GPAC Recommendation
The GPAC voted unanimously in
favor of PHMSA’s proposed amendment
with respect to plastic pipe
requirements, provided PHMSA correct
the minimum wall thickness tables to
specify a 0.099-inch wall thickness for
1-inch CTS plastic pipe as
recommended in the written comments
from the Associations and NAPSR.
3. PHMSA Response
Based on the comments, the final rule
adopts the plastic pipe amendments as
proposed except for a change to the
minimum wall thickness required to use
plastic pipe with a size of 1-inch CTS
with a design factor of 0.40 rather than
0.32. The final rule incorporates the
0.099-inch minimum wall thickness for
1-inch CTS plastic pipe.
PHMSA expects that the
incorporation of updated industry
standards pertaining to plastic pipe
design will not adversely affect safety.
The updated standards incorporated by
reference in this final rule reflect the
benefit of testing, lessons learned, and
operational best practices from the
increasingly widespread use of plastic
pipe in gas transmission, distribution
and gathering applications.
Significantly, those updated industry
standards reflect a greater comfort
within industry regarding the safety of
the use in those applications of largerdiameter plastic piping when subject to
rigorous design standards. Based on its
review of those standards and the
administrative record in this
rulemaking, PHMSA is similarly
satisfied that their incorporation within
the PSR will not have a detrimental
impact on safety. PHMSA has provided
a discussion of the changes in the
updated editions of ASTM D2513 and
ASTM F2620 in the summary of the
proposed changes in section III.G.1
above.
ASTM D2513 and PE Pipe Diameter
The final rule incorporates by
reference the 2018a edition of ASTM
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D2513 and allows the use of a 0.40
design factor for PE pipe produced on
or after the effective date of the rule
with a maximum diameter of 24 inches
as proposed in the NPRM. PHMSA
proposed no changes to the design
pressure formula for PE pipe at
§ 192.121(c)(2), and therefore declines to
adopt the design factor change for PE
piping suggested by PPI without the
benefit of further technical evaluation
and public comment. Similarly, PHMSA
may consider allowing an operator to
more directly establish a HDB rating at
180 °F within the design pressure
formula at § 192.121(a) in a future
rulemaking after further review of the
safety effects of such a change. PHMSA
notes that § 192.121(a) allows an
operator to interpolate the design
pressure down from 180 °F, meaning
they could use a pipe with an HDB
rating at 180 °F but have to use a
formula to determine the design
pressure at a lower temperature listed in
§ 192.121(a). PHMSA cautions users that
not all PE compounds are rated at
180 °F.
Regarding the GPA Midstream
comment concerning other documents
that are currently incorporated into part
192, PHMSA periodically issues rules
updating the standards that are
incorporated by reference, provided the
2018 edition of ASTM D2513 has been
evaluated and its incorporation
determined consistent with PHMSA’s
safety mission. More recent versions of
this and other standards incorporated by
reference, including those related to
plastic pipe and components, that were
not included in the NPRM may be
considered for updates in other
rulemaking proceedings.
ASTM F2620 and Joining Requirements
The final rule also adopts the
clarifications to joining requirements as
proposed with minor editorial revisions.
PHMSA did not propose in the NPRM
to incorporate by reference PPI TR–33,
PPI TR–41, or ISO/IEC 17025, and
therefore declines to incorporate them
by reference without the benefit of
additional public comment and
technical evaluation. However, PHMSA
understands that many of the
procedures in TR–33 and TR–41 are
similar or identical to the procedures
specified in the 2019 edition of ASTM
F2620. There are, however, still some
differences such as heating
temperatures. If an operator can
demonstrate that their alternative
procedure based on those documents
provides an equivalent or superior level
of safety compared with ASTM F2620,
it would be acceptable under the
amendments adopted in this final rule.
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PHMSA disagrees with comments that
including the phrase ‘‘or superior’’
imposes new requirements or adds
uncertainty to the changes in §§ 192.281
and 192.285. An operator need only
demonstrate that their alternative
procedure provides an equivalent level
of safety; the addition of the term ‘‘or
superior’’ exists to ensure that a
procedure with requirements that may
be more conservative than ASTM F2620
is also acceptable. PHMSA has revised
the regulatory language at § 192.281
proposed in the NPRM to clarify that the
operator need only demonstrate that the
alternative procedure provides an
equivalent or superior level of safety
rather than demonstrate the alternative
procedure is itself superior.
1-Inch CTS Pipe
PHMSA agrees with commenters that
0.099 is an acceptable minimum wall
thickness specification. While 0.101
inches more closely corresponds to SDR
11, both 0.099-inch and 0.101-inch wall
thickness for 1-inch CTS pipe are
technically SDR 11 specifications. In
addition, the two specifications are
within allowable tolerances of each
other in the ASTM codes. Therefore,
PHMSA does not have a safety concern
with using a 0.40 design factor with
0.099-inch wall thickness for 1-inch
CTS plastic pipe and recognizes that it
is in common use.
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H. Test Requirements for Pressure
Vessels (Section 192.153)
1. PHMSA’s Proposal
Section 192.153 defines design
requirements for prefabricated units and
pressure vessels (hereafter referred to as
pressure vessels) fabricated by welding.
In particular, § 192.153(a) requires that
operators establish the design pressure
of components fabricated by welding
whose strength cannot be determined to
establish the design pressure of those
components in accordance with section
VIII, division 1 of the 2007 edition of
the American Society of Mechanical
Engineers (ASME) Boiler and Pressure
Vessel Code (BPVC) which is
incorporated by reference in § 192.7.52
Section 192.153(b) requires operators to
design, construct, and test prefabricated
units that use plate and longitudinal
seams in accordance with either ASME
BPVC section I, section VIII, division 1,
or section VIII, division 2. In addition,
§ 192.505(b) requires operators to
pressure test compressor station,
regulator station, and measuring stations
to Class 3 location test requirements; for
pipelines installed after November 11,
52 ASME Boiler & Pressure Vessel Code, 2007
edition (July 1, 2007).
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1970, this represents a required test
factor of at least 1.5 times the maximum
allowable operating pressure (MAOP).53
On March 11, 2015, PHMSA
published a final rule titled, ‘‘Pipeline
Safety: Miscellaneous Changes to
Pipeline Safety Regulations.’’ 54 The
final rule created a new § 192.153(e),
which clarified that pressure vessels
subject to § 192.505(b) must be pressure
tested to at least 1.5 times the MAOP of
the pipeline. INGAA subsequently
submitted a petition for reconsideration
of the Miscellaneous Rule concerning
the revision to § 192.153.55 The
petitioner argued that PHMSA lacked
technical justification for a 1.5 times
MAOP test factor versus the 1.3 times
the Maximum Allowable Working
Pressure (MAWP) 56 test factor
permitted in the ASME BPVC since the
2001 edition and all subsequent editions
of the standard. PHMSA had
incorporated by reference the 2001
edition of the ASME BPVC into part 192
effective July 14, 2004, and the
divergence between the required test
factor in § 192.505(b) and section VIII,
division 1 of ASME BPVC persisted
until the Miscellaneous Rule became
effective in 2015.57
PHMSA, meanwhile, had
commissioned a report by the Oak Ridge
National Laboratory (ORNL) on the
safety equivalence between the 1992
edition and the 2015 edition of the
ASME BPVC. PHMSA understands that
most pressure vessels in pipeline
service are designed to ASME section
VIII, division 1. For hydrostatic pressure
tests, the 1992 edition of section VIII
division 1 of the ASME BPVC provides
for a hydrostatic pressure test factor of
1.5 times MAWP, while the 2001 and all
subsequent editions provide for a
hydrostatic pressure test factor of 1.3
times MAWP. The ORNL report found
that these different editions of ASME
BPVC section VIII, division 1 maintain
safety through the design and
fabrication of pressure vessels and
hydrostatic pressure test,
notwithstanding the difference in their
hydrostatic pressure test factors of 1.3
53 Section 192.619(a)(2) requires a test pressure of
at least 1.5 times the MAOP in a Class 3 or Class
4 location for pipelines installed after November 11,
1970.
54 80 FR 12762 (Miscellaneous Rule).
55 Docket No. PHMSA–2018–0046–0055.
56 MAWP is the design pressure in the ASME
BPVC. The test factors in the ASME BPVC refer to
the MAWP and are used to substantiate the design
pressure of the vessel. Because the design pressure
of a pressure vessel (the MAWP) must be equal to
or greater than the MAOP of the pipeline, the PSR
uses the more demanding MAOP metric.
57 PHMSA, ‘‘Pipeline Safety: Periodic Updates to
Pipeline Safety Regulations,’’ 80 FR 12762 (June 14,
2004).
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and 1.5. A copy of this report is
available in the docket.
In the NPRM, PHMSA proposed to
revise the test requirements for the
pressure vessels described in § 192.153.
First, PHMSA proposed to revise
§ 192.153(e) to require a pressure test
factor of at least 1.3 times the MAOP for
all pressure vessels installed since July
14, 2004, provided the component has
been tested in accordance with the
ASME BPVC, as required by existing
§ 192.153(b). Consistent with this
change and the requirements in the
ASME BPVC, PHMSA also proposed to
exempt vessels installed after July 14,
2004 from the strength testing
requirement at §§ 192.505(b) and
192.619(a)(2), which require a test factor
of 1.5 times the MAOP. The test
requirements for any pressure vessel
with an MAOP established under the
alternative MAOP requirements at
§ 192.620 would remain unchanged.
Second, PHMSA proposed a new
§ 192.153(e)(2) that would exempt
pressure vessels installed after July 14,
2004 but before the effective date of the
final rule from testing duration
requirements at §§ 192.505(c), (d) and
192.507. In contrast, pressure vessels
installed on or after the effective date of
the final rule would be subject to the
long-standing pressure test duration
requirements in subpart J.
Third, PHMSA proposed
§ 192.153(e)(3)(ii) to accept, subject to
certain conditions, a pre-installation
pressure test by the component
manufacturer for pressure vessels
installed after the effective date of the
final rule but which have not previously
been used in service. PHMSA proposed
to accept those manufacturer pressure
tests for the purposes of meeting the
pressure testing and MAOP
requirements in part 192 provided the
operator conducts and documents an
inspection certifying that the pressure
vessel has not been damaged during
transport and installation into the
pipeline. If the inspection reveals that
the pressure vessel has been damaged,
the component would have to be
remediated consistent with the ASME
BPVC and part 192. A pressure vessel
used prior to installation on a pipeline
facility would have to be pressure tested
again, consistent with the existing
requirement at § 192.503(a).
2. Summary of Public Comments
AGA et al. generally supported the
PSR amendments proposed in the
NPRM but suggested substantive
revisions to the requirements for
accepting a manufacturer’s test of a
pressure vessel. AGA et al. emphasized
that the NPRM’s integration of ASME
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BPVC requirements within its proposed
PSR revisions leverages an
internationally recognized standard of
safety applied by several Federal
regulators in their oversight activities.
AGA et al. agreed with the NPRM’s
approach of allowing operators to rely
on a manufacturer’s pressure test
accompanied by a visual inspection for
newly-manufactured vessels, but
requested PHMSA extend this
authorization to relocations of existing
components as well.
AGA et al. noted that retesting ASME
pressure vessels is not required by the
ASME BPVC—but if an operator
voluntarily undertook retesting, the
ASME BPVC would require oversight by
an authorized inspector. They
concluded that retesting is therefore
unnecessary and can lead to costs and
operational disruptions because most
operators do not have an authorized
inspector on staff to oversee that
retesting. They further commented that
PHMSA should not require pressure
vessels be pressure tested or inspected
after installation or in situ, because in
many cases it may be impracticable or
unsafe to do so, especially for pressure
vessels used in compressor stations.
Finally, AGA et al. submitted comments
opposing the NPRM’s proposed
requirement that pressure vessels that
have been used prior to being installed
or relocated must be retested in place in
accordance with Subpart J. They
commented that retesting relocated
vessels is not required by the ASME
BPVC, and that inspection rather than
pressure testing is the appropriate
method to confirm the integrity of
previously-used, relocated pressure
vessels.
PST opposed the proposed revisions
to § 192.153, contending that PHMSA
lacked sufficient technical justification
for the proposed changes. PST argued
that the ORNL report does not support
PHMSA’s conclusion that safety would
not be adversely affected by NPRM’s
proposed reduction of the pressure test
factor at § 192.153(e). PST asserted that
the ORNL report did not conclude that
components designed and fabricated
under the 2015 edition of the ASME
BPVC standards and tested to its lower
(1.3 times MAWP) hydrostatic pressure
test factor were necessarily as safe as
those designed and fabricated to the
higher hydrostatic pressure test factor
(1.5 times MAWP) in the current text of
§§ 192.153(e) and 192.505(b) (which
were based on the test factors from the
1998 and prior editions of the ASME
BPVC). Rather, PST characterizes the
hydrostatic pressure test factor as only
‘‘one of [several] changes between [the]
two editions’’ (1992 and 2015)
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compared by the ORNL report that
would need to be evaluated to
determine the safety impact of the
NPRM’s revisions to § 192.153
compared to the current PSR. PST also
noted that the NPRM proposed applying
the lower test factor in the 2015 ASME
BPVC not only to components installed
since the 2015 edition, but also
components installed over the previous
decade. Lastly, PST alleged that the
NPRM’s proposed reduction in the test
factor at § 192.153(e) violates the
prohibition in 49 U.S.C. 60104(b) on
retroactive application of design
standards insofar as it purports to
impose new design, installation,
construction, and testing standards on
previously-installed components. PST
representatives reiterated their concerns
in a conversation with PHMSA
personnel after the GPAC meeting.
The GPAC members voted 11–2 in
favor of PHMSA’s proposed
amendments with respect to test
requirements for pressure vessels
provided that PHMSA make the
following changes:
• Clarify in the NPRM’s
§ 192.153(e)(3) that testing or inspection
of a pressure vessel must take place after
being placed on its supports at its
installation location, but may occur
prior to tie-in with station piping.
• Clarify in the NPRM’s
§ 192.153(e)(3) that relocated vessels
must meet current design and
construction requirements, be retested
by the operator, and be inspected as
described in the previous
recommendation, to ensure there are no
injurious defects.
• Clarify in a new § 192.153(e)(4) that
the retesting requirements applicable to
pressure vessels do not apply to those
pressure vessels that are used for
temporary maintenance and repair
activities, such as portable launcher or
receivers, temporary odorant tanks,
blow down equipment, and other
similar equipment, but they must be
inspected for safety and integrity prior
to usage.
Two GPAC members representing
EDF and PST voted against the
proposed amendments, expressing
concern that the retroactivity
prohibition at 49 U.S.C. 60104(b)
prohibits PHMSA from applying a
revised test factor to existing pressure
vessels. During the meeting, PHMSA
committed to the GPAC members that it
would consider the application of 49
U.S.C. 60104(b)’s prohibition to the
changes proposed in the NPRM.
INGAA, AGA, APGA, API, and GPA
Midstream submitted joint
supplemental comments after the GPAC
Meeting supporting the GPAC
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recommendation and asserting that the
proposed PSR amendments did not
violate the 49 U.S.C. 60104(b)
retroactivity prohibition. GPA
Midstream separately submitted
supplemental comments on that
statutory retroactivity prohibition,
explaining by reference to its legislative
history, contemporaneous DOT
interpretation of the relevant statutory
language, and subsequent PHMSA
interpretations of the same that 49
U.S.C. 60104(b) prohibits only
generically-applicable, retroactive
standards imposing new compliance
burdens on relevant pipelines. Here, in
contrast, GPA Midstream contended the
NPRM’s proposed revisions to
§ 192.153(e) would relieve regulatory
burdens and operators would have to
take no action to be in full compliance
with the amended § 192.153(e).
3. PHMSA Response
After considering the comments and
the GPAC, PHMSA is adopting the
proposed testing requirements for
pressure vessels subject to certain
amendments to the proposed rule with
respect to test requirements for pressure
vessels in § 192.153. The final rule
adopts the revision to § 192.153(e)(1),
which specifies that a prefabricated unit
or pressure vessel that is installed after
July 13, 2004 is not subject to the
strength testing requirements at
§§ 192.505(b) provided it has been
tested in accordance with § 192.153(a)
or (b) and with a test factor of at least
1.3 times the intended MAOP,
consistent with the hydrostatic pressure
test factors in section VIII, division 1 of
the ASME BPVC. The final rule also
adds a footnote to table 1 to the
§ 192.619(a)(2)(ii) MAOP requirements
specifying that the factor for
establishing the MAOP of a
prefabricated unit or pressure vessel
installed after July 14, 2004 is 1.3 times
the MAOP. These changes ensure that
an operator of a pressure vessel
designed and hydrostatically tested in
accordance with section VIII, division 1
of the ASME BPVC since the
incorporation by reference of the 2001
edition of that document is compliant
with the PSR. This allows an operator
of a pressure vessel designed and
hydrostatically tested in accordance
with section VIII, division 1 of the
ASME BPVC to operate it at an MAOP
equal to its design pressure in most
instances. PHMSA notes that if the
pressure vessel is tested at factor lower
than 1.3 times the MAWP under a
pneumatic test or under section VIII
division 2 of the ASME BPVC, the
MAOP of the pipeline must be
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established such that the test pressure is
1.3 times the MAOP or greater.
PHMSA understands the
administrative record shows that this
rulemaking’s revision of the pressure
test factors at § 192.153 does not
adversely affect the safety of pressure
vessels designed, constructed, and
tested in accordance with the 2001 and
subsequent editions of the ASME BPVC,
and designed, tested, constructed, and
operated in accordance with the PSR.
PHMSA therefore disagrees with PST’s
assertion that the ORNL report does not
contribute to the technical justification
for that change. PST is correct to note
that the ORNL report compares the 1992
and 2015 editions of the ASME BPVC,
and that other changes have taken place
within the intervening editions of that
standard (including the 2007 version
currently incorporated by reference in
the PSR). However, the ORNL report did
not provide only a top-level statement of
safety equivalence between the 1992
and 2015 editions of the ASME BPVC;
it also evaluated the contributions to
that ultimate conclusion from each of
the material elements of the 1992 and
2015 editions ASME BPVC—including
the effects of a reduction in the
hydrostatic pressure test factor in ASME
BPVC section VIII, division 1 from 1.5
times the MAWP to 1.3 times the
MAWP.58
The ORNL report predicated its toplevel conclusion of safety equivalence
across the 1992 and 2015 editions of the
BPVC section VIII, division 1,
notwithstanding their different
hydrostatic pressure test factors, in part
on certain shared features. The most
important of those features was that
both editions’ hydrostatic pressure test
factors yield hydrostatic pressure testing
limits that ensure primary membrane
stresses remain at or below plastic
collapse stress limits for a pressure
vessel, thereby reducing the risk of
permanent distortion that would result
in rejection of the pressure vessel at
qualification. Other features shared
between the 1992 and 2015 editions of
BPVC section VIII, division 1
contributing to ORNL’s safety
equivalence finding include the
following: Pressure testing by an
authorized inspector at qualification
verifying leak-tight integrity and the
absence of gross deformations and
anomalies indicative of design errors,
material defects, or weld defects;
pressure testing after fabrication
verifying leak-tight integrity and the
58 ORNL report at Table 9.2 (summarizing Section
7.1.2.1 of the ORNL report on the safety
contribution of hydrostatic test factors in different
editions of ASME BPVC section VIII, division 1).
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absence of gross deformations and
anomalies indicative of design errors,
material defects, or weld defects; and
overpressure protection in the event of
design basis heat exposure ensuring that
maximum overpressure does not exceed
1.3 MAWP.
Each of the features listed above are
also shared by the 2007 edition of the
BPVC section VIII, section 1
incorporated by reference in the PSR,
notwithstanding any other differences
between that edition and the 1992 and
2015 editions evaluated in the ORNL
report. Like the 1992 and 2015 editions,
the various design requirements of the
2007 edition of the ASME BPVC ensure
that plastic stresses on a pressure vessel
remain at or below plastic collapse
stress limits to avoid permanent
distortion. And like the 1992 and 2015
editions, the 2007 edition backstops that
design basis by qualified inspections to
identify defects, post-fabrication
pressure testing, and overpressure
protection from a design basis heat
exposure. Insofar as ORNL determined
that these shared features contributed to
its top-level conclusion of safety
equivalence between the 1992 and 2015
editions of the ASME BPVC, PHMSA
understands them to support its
conclusion in this final rule that that a
lower (1.3) test factor will not adversely
affect safety.
PHMSA also submits that other
elements of this final rule and the PSR’s
comprehensive safety regime support
the conclusion that lowering the test
factor to 1.3 will not adversely affect
safety. The applicability of the ASME
BPVC in the PSR is limited to the
design, testing and fabrication of
pressure vessels. On the other hand, the
PSR applies additional requirements
throughout the lifecycle of a pressure
vessel to ensure its continued integrity
and safe operation. These requirements
pertain to construction (subpart G),
corrosion control (subpart I), testing
(subpart J), operation (subpart L),
maintenance (subpart M), and integrity
management (subparts O and P)
standards. Further, even with respect to
design and installation standards that
are the focus of ASME BPVC section
VIII, division 1, PSR requirements
provide additional assurance that
stresses remain within safe limits. For
example, § 192.201(a)(2)(i) requires
overpressure protection devices be set to
discharge at 1.1 times MAOP or at a
pressure producing a hoop stress of 75
percent of SMYS, whichever is lower—
a requirement that is more conservative
than analogous overpressure
specifications in the ASME BPVC
referenced in the ORNL report.
Similarly, the ASME BPVC does not
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specify a minimum pressure test
duration. In contrast, the PSR at subpart
J requires a minimum pressure test
durations of 8 hours (§ 192.505(c)), 4
hours (§ 192.505(d)), 1 hour
(§ 192.507(c)), or with a procedure
sufficient to ensure discovery of all
potentially hazardous leaks (§ 192.509).
PHMSA further notes that exemption
in this final rule from subpart J’s
minimum pressure duration
requirements are consistent with that
conclusion. Prior to the changes
adopted by this final rule, if an operator
tested a pressure vessel to 1.3 times the
MAOP consistent with section VIII,
division 1 of the ASME BPVC rather
than 1.5 times the MAOP, it would not
comply with the PSR. An operator of
such a vessel would need to reduce the
MAOP of the pressure vessel such that
the test pressure is 1.3 times the
reduced MAOP, retest the vessel to 1.5
times the MAOP, or replace the pressure
vessel entirely. Likewise, a pressure
vessel that was not tested for a duration
specified in subpart J would need to be
retested or replaced to remain in
compliance. While retesting or replacing
existing pressure vessels with a longer
test duration or higher test factor could
conceivably decrease the risk of an
overpressure event causing a vessel
failure on affected pipelines, PHMSA
understands any such safety benefit
could be speculative; incident reports
indicate that pressure vessel failure has
not been an issue on existing vessels inservice.
This is further supported by the
conclusions of the ORNL report with
respect to the hydrostatic pressure
testing limits described above. Further,
any potential safety benefit from
retesting or replacing pressure vessels
already in service would need to be
weighed against new safety risks that
may emerge from such activity. And
here PHMSA understands that re-testing
and replacing in-service pressure
vessels in pipeline facilities can entail
its own safety hazards for operator
personnel due to the mass, volume, and
installation location of a typical
pressure vessel compared with other
types of pipeline facilities. Specifically,
retesting or replacement of a pressure
vessel requires purging of gas,
disconnection from local piping, and
likely removal from service and
reinstallation. The pipeline facilities
involved in such efforts may be very
heavy and large, which increases
hazards to operator personnel when the
pressure vessel or other equipment is
removed from its installation location
and prepared for testing. The layout of
compressor stations and other facilities
may exacerbate these safety risks if there
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is limited space to safely remove the
pressure vessel or to maneuver lifting
equipment. Each of these steps therefore
introduces certain safety risks to
operator personnel performing the work
that PHMSA believes could outweigh
any marginal, speculative safety benefit
from re-testing and replacement of
previously-installed pressure vessels.
Lastly, as pointed out by multiple
comments submitted on the NPRM,
such re-testing and replacement of
existing pipe could entail significant
costs and operational disruptions that
similarly militate in favor of the
exemption in the final rule.
Finally, PHMSA notes that the ASME
BPVC does not specify minimum test
duration requirements and part 192
does not currently require postinstallation inspection of pressure
vessels. The final rule’s PSR amendment
clarifying that these requirements apply
to new, replaced, relocated, or otherwise
changed pressure vessels installed after
the effective date of the final rule are
expected to result in an increased level
of safety.
The final rule retains the proposed
requirement to inspect pre-tested
pressure vessels after being placed at the
vessel’s installation location on its
support structure in § 192.153(e)(3).
However, consistent with the GPAC’s
recommendations, the final rule clarifies
that those inspections may occur prior
to the pressure vessel tie-in on-site with
the pipeline. PHMSA appreciates
comments that testing vessels after they
have been tied-in to station piping may
be problematic depending on what or
how it is being connected. But one of
the risks of transporting pressure vessels
and other large components is damage
to the vessel including vessel outlets or
its support structure while it is being
moved within the facility itself. Many of
the considerations raised by
commenters that may complicate an
inspection likewise raise the likelihood
of potential damage during installation.
For example, it would be unusual for a
pressure vessel to be completely
inaccessible in a typical compressor
station configuration. In addition, since
the § 192.153(e)(3) requirement applies
to new, replaced, and relocated vessels,
operators can ensure access during
initial design, construction, and testing
stages. The final rule also clarifies that
operators must visually inspect the steel
structure for damage including, at a
minimum: Inlets, outlets, and lifting
points. If damage is found, the pressure
vessel must be non-destructively tested,
re-pressure tested, or remediated in
accordance with part 192 and ASME
BPVC requirements. Test, inspection,
and repair records must be kept for the
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operational life of the pressure vessel.
These clarifying revisions to
§ 192.153(e)(3) are designed to enhance
safety, address the most significant
concerns operators had with postinstallation inspection, and help ensure
that damage incurred during movements
within the facility are detected and
remediated before the pressure vessel is
put into service.
PHMSA has also, consistent with the
GPAC’s recommendations, clarified
when testing and inspection under
§ 192.153(e)(3) is required. The final
rule clarifies that any pressure vessel
that is temporarily or permanently
installed in a pipeline facility must be
inspected for damage as described above
unless it has been pressure tested on its
supports at its installation location. This
includes pressure vessels that are
pressure tested by the operator prior to
installation when a post-installation
pressure test is impracticable
(§§ 192.505(d) and 192.507(d) in the
final rule) and to pressure vessels where
a manufacturer’s pressure test is used
under § 192.153(e)(4) in the final rule.
This change is consistent with
pretesting authorizations under
§ 192.507(d) in the final rule or
§ 192.505(d) in existing part 192. It
preserves the flexibility provided under
those authorizations while the postinstallation inspection ensures that pretested components are not damaged
after being tested by the manufacturer or
the operator.
The final rule also clarifies design,
testing, and inspection requirements for
pressure vessels that are relocated.
Consistent with the GPAC’s
recommendations, PHMSA is adding a
new § 192.153(e)(6) that clarifies testing
and inspection requirements for
relocating an existing pressure vessel
that has previously been used in service
for permanent installation at a new
location in a pipeline facility. An
operator must have documentation that
a relocated pressure vessel meets the
design, construction, and testing
requirements in place at the time of
relocation and pressure test the pressure
vessel. If a pre-installation pressure test
is performed, the operator must inspect
the pressure vessel after installation.
The final rule does not adopt
suggestions from commenters to accept
a manufacturer’s initial pressure test for
all relocated pressure vessels. PHMSA
did not propose specific changes to the
initial pressure testing requirements for
relocated, existing pressure vessels.
Rather, the requirements in the final
rule for permanently relocated vessels
complement existing part 192
requirements for relocation of existing
facilities with the addition of a new,
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general requirement in § 192.153(e)(3) to
inspect pressure vessels that are not
pressure tested in place. Using a
manufacturer’s initial pressure test of an
existing vessel raises safety concerns
because the vessel could have been
subject to corrosion, fatigue, external
force damage, and other threats to the
vessel’s integrity during its prior
operational life or during transportation
to the new facility.
The GPAC’s discussion noted that
operators commonly use such
temporary devices for temporary
launchers and receivers for integrity
assessments and to reduce methane
emissions during blowdowns (natural
gas is predominately methane, a
greenhouse gas). PHMSA did not intend
to impair the use of pressure vessels that
are relocated temporarily in order to
perform maintenance, repair, or
emergency-response-related tasks. To
prevent this unintended result, PHMSA
is incorporating a new § 192.153(e)(4)(ii)
to allow the use of a manufacturer’s
initial test of a pressure vessel
temporarily installed in a pipeline
facility to complete a testing, integrity
assessment, repair, odorization, or
emergency response-related task,
including noise or pollution abatement.
This revision addresses temporary and
mobile pressure vessels that were
discussed during the GPAC meeting,
including portable launcher or
receivers, temporary odorant tanks,
mobile blow down equipment, and
other similar equipment. This change
reduces barriers to using temporary
equipment to perform integrity
assessment, maintenance, and pollution
mitigation-related tasks (provided the
equipment meets the MAOP, design,
and inspection requirements in part
192) and thereby is expected to result in
greater efficiency for operators and
safety and environmental benefits
associated with encouraging inspections
and repairs. These devices are subject to
the new general requirement in
§ 192.153(e)(3)(ii) to inspect pressure
vessels that are not pressure tested in
place after installation. Reducing
regulatory burdens associated with
performing maintenance, repair,
emergency response, and pollution
abatement tasks could result in safety
and environmental benefits by making
such actions more attractive to
operators.
To prevents misuse of this flexibility,
a pressure vessel that is installed under
§ 192.153(e)(4)(ii) must be removed
when the task it is associated with is
completed. Operators should define the
procedures for employing temporary or
mobile pressure vessels in their written
procedure manuals. The final rule
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requires operators to submit a
notification to PHMSA and applicable
State pipeline safety authorities in
accordance with § 192.18 if a temporary
pressure vessel must be left in place for
longer than 30 days; however, PHMSA
does not reference this section in
§ 192.18(c) and therefore the objection
process and advance notice
requirements do not apply. Likewise,
§ 192.153(e)(5) clarifies that an operator
is not required to pressure test a
pressure vessel that is temporarily
removed from a facility to perform a
maintenance task and later re-installed
at the same location. However, the reinstalled pressure vessel must be
inspected in accordance with
§ 192.153(e)(3)(ii) after it is re-installed.
Generally, PHMSA does not consider
small movements within the same
location (e.g. within a compressor
station) with no other operational
changes as a relocation, however the
operator should inspect the vessel for
damage after installation.
PHMSA has considered the comments
by PST and members of the GPAC
regarding the nonapplication
requirement and finds the revisions to
49 CFR 192.153(e) are not inconsistent
with 49 U.S.C. 60104(b). Section
60104(b) provides that a ‘‘design,
installation, construction, initial
inspection, or initial testing standard
does not apply to a pipeline facility
existing when the standard is adopted.’’
Under the revised § 192.153, operators
of existing pressure vessels that meet
minimum testing requirements will not
be required to take any additional action
to comply. While the revised section
requires that components be pressure
tested with a test factor of at least 1.3
times MAOP, the current § 192.153(e)
already required such testing at even
higher pressures; in other words, a
pressure vessel compliant with the
existing § 192.153(e) would also be
compliant with § 192.153(e) as revised
by this final rule. The revisions to the
PSR, therefore, cannot be said to impose
a new standard on existing facilities in
conflict with 49 U.S.C. 60104(b).
In addition, as described in the
preamble to the NPRM, the amendment
to 49 CFR 192.153(e) responds to a
petition for reconsideration of the
Miscellaneous Rule.59 This final rule
addresses the issues raised by the
petition challenging the addition of
§ 192.153(e) in the Miscellaneous Rule
pursuant to the reconsideration
procedures in part 190. The petition for
reconsideration of the Miscellaneous
Rule argues PHMSA’s modifications to
59 Available in docket No. PHMSA–2010–0026
and the docket for this final rule.
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§ 192.153 were not merely clarifications
regarding the required testing standard
for pressure vessels as PHMSA stated in
the Miscellaneous Rule, but rather were
departures from the testing standard for
pressure vessels in the ASME BPVC
standard that was incorporated in the
regulations at the time. PHMSA
maintains that the Miscellaneous Rule
merely clarified the required testing
standard for pressure vessels, but
understands there was ambiguity in the
regulations regarding the testing
standard for pressure vessels before the
Miscellaneous Rule was passed and that
the Miscellaneous Rule codified a
higher testing standard than many
operators reasonably believed was
compliant with the regulations at the
time. Also, based on the discussion
above, PHMSA was able to verify that
the provisions in the final rule will not
adversely affect safety. PHMSA is
therefore allowing pressure vessels
tested in accordance with the 1.3 test
factor after 2004 to continue operating
without retesting in order not to
penalize conduct some operators
believed complied with the PSR at the
time.
Lastly, because PHMSA understands
the PSR revisions in this final rule
obviate the need for its unpublished
October 27, 2015 letter to INGAA
announcing a stay of enforcement
pertaining to certain pressure vessels in
violation of §§ 192.153(e) and
192.505(b), it withdraws that document
as of the effective date of this final rule.
This letter is also available in the docket
for this final rule.
I. Welding Process Requirement (Section
192.229)
1. PHMSA’s Proposal
Section 192.229(b) currently bars
welders from welding with a welding
process if they have not engaged in
welding with that same process within
the previous six months. GPTC
submitted a petition for rulemaking
requesting PHMSA revise § 192.229(b)
to allow welders to demonstrate they
have engaged in welding with a welding
process at least twice each calendar
year, but at intervals not exceeding 71⁄2
months, provided the welds were tested
and found acceptable in accordance
with API Standard (Std) 1104.60 API Std
1104 is the primary standard for
welding steel piping and for testing
welds on steel pipelines, and covers the
requirements for welding and
nondestructive testing of pipeline
welds. API Std 1104 is used within part
192 requirements for qualifying welders,
60 Docket
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welding procedures, and welding
operators, and interpreting the results of
non-destructive tests.
GPTC also noted that the 6-month
frequency requirement for the welding
process requirement at § 192.229(b) is
different than other requirements in
§ 192.229(c)(1) and (d)(2) governing
welder requalification frequency. Those
welder requalification requirements
demand requalification within the
preceding 71⁄2 months, but at least twice
each calendar year. GPTC pointed out
that this discrepancy between welder
process requirements and welder
requalification requirements obliged
operators either to maintain alternative
recordkeeping procedures for the
process requirement or perform welds to
comply with both the process
requirement and the requalification
requirements on a 6-month interval. In
other words, if a welder wishes to use
the same weld to comply with both
requirements, they are unable to benefit
from the more flexible welder
requalification requirements at
§ 192.229(c)(1) and (d)(2).
PHMSA proposed in the NPRM to
revise § 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
71⁄2 months and the welds were tested
and found acceptable in accordance
with API Std 1104. This change would
provide operators some flexibility in
scheduling welding activities to
maintain welder requalification.
PHMSA agrees with GPTC that the
proposed revision is more consistent
with § 192.229(d)(2). This is potentially
beneficial for welders who weld
relatively infrequently. PHMSA does
not anticipate a decrease in safety, as a
71⁄2-month interval is already permitted
for requalification under
§ 192.229(d)(2)(i), and the change will
only affect welders who are not welding
throughout the year.
2. Summary of Public Comments
AmeriGas, AIPRO, FreedomWorks,
NPGA, Oleksa and Associates, and SPP
supported the proposed requalification
scheduling for welders. Oleksa and
Associates stated that there will be no
negative impact on pipeline safety.
FreedomWorks stated that the changes
would allow welders, many of whom
are self-employed freelancers, greater
flexibility in their trade. AIPRO
commented that the changes would
establish regulatory expectations and
create more scheduling opportunity for
vendors to perform the welding tests
and for companies to comply with the
standard. The GPAC voted unanimously
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in favor of PHMSA’s proposed
amendments regarding the welding
process requirement.
3. PHMSA Response
Based on the comments and the GPAC
recommendations, PHMSA has adopted
this amendment as proposed. This
change will streamline compliance and
recordkeeping activities related to
§ 192.229(b) and will not have a
detrimental impact on safety.
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J. Pre-Test Applicability (Section
192.507)
1. PHMSA’s Proposal
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
of 30 percent or more of SMYS if a postinstallation test is not practicable.
PHMSA proposed in the NPRM to add
a new paragraph (d) to § 192.507 to
extend this authorization to steel
pipelines operated at a hoop stress less
than 30 percent of SMYS and at or
above 100 psig.61
The NPRM’s proposed revision is in
response to a petition for rulemaking
submitted by GPTC for PHMSA to
relocate the pre-installation strength
testing requirement at § 192.505(d) to
the general test requirements in
§ 192.503 to permit broader application
of this authorization. GPTC argued this
change would permit operators to use
pre-tested pipe and fabricated units in
applications outside of higher stress
transmission pipelines. GPTC further
asserted that as this provision is
currently applicable only to higherstress pipelines operating at a hoop
stress at or greater than 30 percent of
SMYS, extending the broader pre-testing
provision to lower-stress pipelines
would not increase pipeline safety risks.
Rather, GPTC predicted this proposed
change will provide greater flexibility
and efficiency for operators of lowerstress pipelines, especially during
maintenance activities.
Instead of adding pre-testing
provisions to the general requirements
at § 192.503 as suggested by the GPTC
petition, PHMSA proposed in the NPRM
to add § 192.507(d) to permit pre-testing
on steel pipelines operating at a hoop
stress less than 30 percent of SMYS and
at or above 100 psig. The proposal did
not extend pre-testing provisions to
pipelines operating below 100 psig
(§ 192.509), service lines (§ 192.511), or
plastic pipelines (§ 192.513). Individual
components, excluding short segments
61 ‘‘Pounds per square inch gauge’’ refers to
internal pressure relative to outside atmospheric
pressure.
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of pipe, may still be installed on those
facilities with a pre-installation test
pursuant to § 192.503(e). PHMSA
requested comments on whether it is
appropriate to extend pre-testing
provisions to such facilities, and
solicited proposed requirements that
should apply if pre-testing provisions
are extended to such facilities.
2. Summary of Public Comments
AmeriGas, NPGA, and SPP supported
the proposed changes to § 192.507 to
allow operators to extend the
authorization for pre-testing fabricated
assemblies to include steel pipelines
that operate at a hoop stress less than 30
percent of SMYS and at or above 100
psig. Similarly, PST commented that
they did not object to extending the pretesting provisions to lower stress
pipelines as proposed in the NPRM.
AGA et al., National Fuel, and Oleksa
and Associates recommended that
PHMSA consider extending the pretesting allowance to other pipelines that
also pose less of a safety risk.
Specifically, they recommended that
PHMSA extend the allowance for pretested short segments of pipe and
fabricated units to steel pipelines that
operate at pressures less than 100 psig
(§ 192.509), plastic pipelines
(§ 192.511), and service lines (§ 192.513)
to provide clarity and consistency
within the regulations. These
commenters suggested the addition of
enabling regulatory text. Oleksa and
Associates agreed with these
commenters, stating that the rationale
that applies to permitting pre-tested
pipe on steel pipelines operating at a
stress less than 30 percent of SMYS and
at or above 100 psig applies in the same
way to pipelines operating below 100
psig, service lines, and plastic pipelines.
They suggested that the simplest way to
accomplish this is to modify the
wording in § 192.503.
Similarly, NAPSR opposed the
proposed revision unless it is revised to
allow the use of pre-tested pipe for main
repairs under 100 psig. Specifically,
NAPSR commented that it may be
impracticable to pressure test Type B
gathering lines and mains postinstallation. They commented that if
pre-tested pipe is allowed for systems
that operate above 100 psig and above
30 percent SMYS, then pre-tested pipe
should also be allowed for all pipe that
operates below 100 psig and low stress
pipe. NAPSR believes that most
operators use pre-tested pipe for main
and Type B gathering line repairs as a
standard practice; that pipe is soap
tested and visually inspected for leaks
after installation. They stated that the
proposed change in the NPRM could
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unnecessarily restrict operators from
safely and quickly repairing damages,
and that distribution operators could
potentially experience prolonged
outages (especially in cold weather) and
increased repair times and cost if pretested pipe is not allowed.
AGA et al. commented that in 2019,
distribution system operators reported
84,608 leaks caused by excavation
damage on their Gas Distribution
Annual Reports. Assuming each
excavation damage related leak required
a pressure test, and assuming a cost of
$200 per post-installation pressure test,
they stated that the cost would be nearly
$17 million annually to pressure test
pipe replaced due to excavation damage
alone. National Fuel’s comment
included a similar calculation and
estimated $8.8 million in cost savings if
pre-tested pipe is allowed for such
repairs. These commenters asserted that
the use of pre-tested pipe would
significantly reduce these costs as
operators could pre-test full joints or
coils of pipe for use on multiple short
segment replacements and repairs
without compromising safety.
National Fuel commented that
extending pre-testing to distribution
lines would allow the use of pre-tested
pipe for short segment replacements for
leak repairs, excavation damage repairs
and replacement of visually
questionable welds or plastic fusion
joints. They noted that without this
change operators are required to test
short replacement segments in place,
which is inefficient, time consuming,
and often results in extended shutdown
durations and inconvenience to
customers. They further stated that
based on current regulatory language, an
excavation damage repair that involves
replacement of two feet of plastic
distribution main requires that the
operator: (1) Fuse end caps on each end
of the replacement segment, (2) pressure
test the pipe in place for the required
duration, (3) remove the end caps, (4)
tie-in the replacement segment by
electrofusion or coupling, and (5) purge,
gas and soap test the joints. They stated
that allowing the use of pre-tested pipe
would significantly reduce the repair
time and costs to complete the repair
and would still result in a pipe segment
that is both strength tested and leak
tested to ensure an equal level of safety
while limiting interruptions to
customers.
AGA et al. recommended that
PHMSA remove the term ‘‘hydrostatic’’
from the test requirements for short
segments of pipe and pre-fabricated
units from § 192.507 because natural
gas, inert gas, and air are also allowable
test media for pipelines operating at a
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hoop stress less than 30 percent of
SMYS under § 192.503(c).
The GPAC voted unanimously in
favor of PHMSA’s proposed PSR
amendments regarding the welding
process requirement but recommended
removing the word ‘‘hydrostatic’’ from
the proposed § 192.507(d).
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3. PHMSA Response
Based on the comments received and
the recommendation of the GPAC, the
final rule adopts the amendments
related to pre-testing fabricated
assemblies and short segments of pipe
as proposed in the NPRM, except that
PHMSA has removed the term
‘‘hydrostatic’’ from the new
§ 192.507(d). PHMSA agrees that
removing the term ‘‘hydrostatic’’ is
appropriate since other test media other
than water are approved for use in that
new section.
The final rule does not extend the
authorization in § 192.507 (as revised)
for pre-tested segments of pipe and
fabricated assemblies beyond steel pipe
with an MAOP producing a hoop stress
less than 30 percent of SMYS but at or
above 100 psig. Operators must still
perform leak tests after installing
fabricated units and short segments of
pipe installed on such pipelines. The
remaining categories in subpart J
(metallic pipe with an MAOP less than
100 psig, plastic pipe, and service lines)
generally represent distribution lines
rather than transmission lines. It is not
clear that there is adequate safety
justification for extending the pretesting allowance to these categories of
lines due to the proximity of such
facilities to customers and the
differences in design, construction,
inspection, and testing requirements for
such facilities compared with higherpressure transmission lines. For
example, welds on higher-pressure
metallic lines require inspection with
non-destructive testing techniques
under § 192.241, while plastic pipe
joints and welds on lower-pressure
metallic lines can be visually inspected
instead. The leak tests required for
lower-pressure lines in subpart J are,
therefore, necessary to ensure the leaktight integrity of welds and joints on
such lines. Commenters did not suggest
alternative inspection requirements or
other conditions for using pre-tested
pipe and fabricated units on such
pipelines. PHMSA therefore determined
that additional analysis is necessary to
consider the safety effects of extending
the pre-testing allowance to such
facilities, and what, if any, additional
conditions may be necessary. The GPAC
voted unanimously in favor of this
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recommended approach. PHMSA may
consider this issue in future rulemaking.
PHMSA notes that §§ 192.509,
192.511, and 192.513 require only a leak
test. NAPSR presented a scenario where,
for a replacement repair, an operator
installed pre-tested pipe and then
performed a leak test after installation.
The leak test described in this scenario
meets the post-installation leak test
requirement in § 192.509, provided that
the operator’s test procedure ensures the
discovery of all potentially hazardous
leaks.
IV. 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 80
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.
The National Technology Transfer
and Advancement Act of 1995 (Pub. L.
104–113; NTTAA) 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, the Office of
Management and Budget (OMB) issued
Circular A–119 62 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 is responsible
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. 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. Revisions to
materials incorporated by reference in
the PSR are handled via the rulemaking
62 OMB, Circular A–119, ‘‘Federal Participation in
the Development and Use of Voluntary Consensus
Standards and in Conformity Assessment
Activities’’ (Jan. 27, 2016). Circular A–119 and
revisions thereto are available at https://
www.whitehouse.gov/omb/information-foragencies/circulars/.
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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. 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.63
To meet these obligations 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/rightsand-usage-policy#tab-ibr-reading-room
and is discussed in greater detail in
section I.1 of this preamble. The ASTM
standards are available at https://
www.astm.org/READINGLIBRARY/ and
are discussed in greater detail in section
G.1 of this preamble. PHMSA will also
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:
phmsaphpstandards@dot.gov. PHMSA
also notes that standards incorporated
by reference in the PSR can be obtained
from the organization developing each
standard. Section 192.7 provides the
contact information for each of those
standard-developing organizations.
V. Regulatory Analyses and Notices
A. Legal Authority for This Rulemaking
This rule is published under the
authority of the Federal Pipeline Safety
Law (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, § 60102(l) of the Federal
Pipeline Safety Law 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 § 60102 to the
63 79
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Administrator of PHMSA in 49 CFR
1.97.
analyzes these economic impacts in
detail.
B. Executive Order 12866 and DOT
Rulemaking Procedures
E.O. 12866, ‘‘Regulatory Planning and
Review,’’ 64 requires agencies to regulate
in the ‘‘most cost-effective manner,’’ to
make a ‘‘reasoned determination that
the benefits of the intended regulation
justify its costs,’’ and to develop
regulations that ‘‘impose the least
burden on society.’’ E.O. 12866 and
DOT regulations governing rulemaking
procedures at 49 CFR part 5 require that
PHMSA submit ‘‘significant regulatory
actions’’ to OMB for review. This rule is
considered significant under § 3(f) of
E.O. 12866, and was reviewed by OMB.
It is also significant under the DOT’s
rulemaking procedures at 49 CFR part 5.
Similarly, DOT regulations at § 5.5(f)(g) require that regulations issued by
PHMSA and other DOT Operating
Administrations ‘‘should be designed to
minimize burdens and reduce barriers
to market entry whenever possible,
consistent with the effective promotion
of safety’’ and should generally ‘‘not be
issued unless their benefits are expected
to exceed their costs.’’
E.O. 12866 and DOT implementing
regulations at 49 CFR 5.5(i) also require
PHMSA to provide a meaningful
opportunity for public participation,
which also reinforces requirements for
notice and comment under the
Administrative Procedure Act (5 U.S.C.
551, et seq.). Therefore, in the NPRM,
PHMSA sought public comment on its
proposed revisions to the PSR and the
preliminary cost and cost savings
analyses in the Preliminary RIA, as well
as any information that could assist in
quantifying the benefits of this
rulemaking. Those comments are
addressed in this final rule, and
additional discussion about the
economic impacts of the final rule are
provided within the final RIA posted in
the rulemaking docket.
PHMSA estimated that this final rule
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 final rule will result in
annualized cost savings of
approximately $129.8 million per year,
based on a 7 percent discount rate. Most
of the quantified cost savings in the
final rule are from the revisions to farm
tap requirements and the revised
atmospheric corrosion reassessment
interval for distribution service lines.
The final RIA in the rulemaking docket
C. Executive Order 13771, ‘‘Reducing
Regulation and Controlling Regulatory
Cost’’
This final rule is an E.O. 13771 65
deregulatory action. Details on the
estimated cost savings of this final rule
can be found in the rule’s economic
analysis within the RIA in the
rulemaking docket.
D. Executive Order 13132—
‘‘Federalism’’
PHMSA analyzed this final rule in
accordance with E.O. 13132.66 E.O.
13132 requires agencies to assure
meaningful and timely input by State
and local officials in the development of
regulatory policies that may have
‘‘substantial direct effects on the States,
on the relationship between the national
government and the States, or on the
distribution of power and
responsibilities among the various
levels of government.’’
This final rule 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 final rule
also does not impose substantial direct
compliance costs on State and local
governments.
The final rule could have preemptive
effect because the Federal Pipeline
Safety Law, specifically 49 U.S.C.
60104(c), prohibits certain State safety
regulation of interstate pipelines. Under
the Federal Pipeline Safety Law, States
may 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 final rule is
limited to the minimum level necessary
to achieve the objectives of the Federal
Pipeline Safety Law under which the
final 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’’
PHMSA analyzed this final rule in
accordance with the principles and
criteria in E.O. 13175 67 and DOT Order
65 82
FR 9339 (Feb. 3, 2017).
FR 43255 (Aug. 10, 1999).
67 65 FR 67249 (Nov. 6, 2000).
5301.1, ‘‘Department of Transportation
Programs, Polices, and Procedures
Affecting American Indians, Alaska
Natives, and Tribes.’’ E.O. 13175
requires agencies to assure meaningful
and timely input from Tribal
government representatives in the
development of rules that significantly
or uniquely affect Tribal communities
by imposing ‘‘substantial direct
compliance costs’’ or ‘‘substantial direct
effects’’ on such communities or the
relationship and distribution of power
between the Federal Government and
Tribes. PHMSA assessed the impact of
the final rule on Indian Tribal
communities and determined that it
would not significantly or uniquely
affect Tribal communities or Indian
Tribal governments. Therefore, the
funding and consultation requirements
of E.O. 13175 do not apply. PHMSA
received no comments to the effect that
this rulemaking would have Tribal
implications.
F. Executive Order 13211—‘‘Actions
Concerning Regulations That
Significantly Affect Energy Supply,
Distribution, or Use’’
E.O. 13211 68 requires Federal
agencies to prepare a Statement of
Energy Effects for any ‘‘significant
energy action.’’ Under E.O. 13211, a
‘‘significant energy action’’ is defined as
any action by an agency (normally
published in the Federal Register) that
promulgates, or is expected to lead to
the promulgation of, a final rule or
regulation (including a notice of
inquiry, ANPRM, and NPRM) that: (1)(i)
Is a significant regulatory action under
E.O. 12866 or any successor order, and
(ii) is likely to have a significant adverse
effect on the supply, distribution, or use
of energy; or (2) is designated by the
Administrator of the Office of
Information and Regulatory Affairs as a
significant energy action.
This final rule is not a ‘‘significant
energy action’’ under E.O. 13211. It is
not likely to have a significant adverse
effect on supply, distribution, or energy
use; rather, it is expected to reduce
regulatory burdens on the natural gas
pipeline sector without adversely
affecting safety. Further, the Office of
Information and Regulatory Affairs has
not designated this final rule as a
significant energy action.
G. Regulatory Flexibility Act and
Executive Order 13272
The Regulatory Flexibility Act (5
U.S.C. 601 et seq.), as implemented by
E.O. 13272, ‘‘Proper Consideration of
Small Entities in Agency
66 64
64 58
FR 51735; Oct. 4, 1993.
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68 66
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Rulemaking,’’ 69 and § 5.13(f) of DOT
regulations, requires Federal regulatory
agencies to prepare a Final Regulatory
Flexibility Analysis (FRFA) for any final
rule subject to notice-and-comment
rulemaking under the Administrative
Procedure Act unless the agency head
certifies that the rule will not have a
significant economic impact on a
substantial number of small entities.
PHMSA has determined that the costsavings in the final rule may result in
significant economic impacts on a
substantial number of small entities.
These impacts on regulated entities are
beneficial. PHMSA has included a
FRFA within the final RIA posted 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.
Pursuant to 44 U.S.C. 3506(c)(2)(B)
and 5 CFR 1320.8(d), PHMSA is
required to provide interested members
of the public and affected agencies with
an opportunity to comment on
information collection and
recordkeeping requests. PHMSA expects
this final rule to impact the information
collections described below.
PHMSA will submit an information
collection revision request to OMB for
approval based on the requirements in
this final rule. The information
collections are contained in the PSR.
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 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 28 fewer gas distribution
incident reports, and 14 fewer gas
transmission reports. Operators
currently spend 12 hours completing
each incident report. Therefore, PHMSA
69 68
FR 7990 (Feb. 19, 2003).
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expects to eliminate 42 responses and
504 hours from this information
collection per year 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: 259.
Total Annual Burden Hours: 3,108.
Frequency of Collection: On Occasion.
2. Title: Annual and Incident 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 MFF 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. In the currentlyapproved information collection, it is
estimated that PHMSA currently
receives, on average, 8,300 MFF 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 PSR require operators of
gas distribution pipelines to develop
and implement IM programs.
PHMSA proposed to eliminate this
requirement for master meter operators.
Based on the currently approved
information collection, 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
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recordkeeping burdens attributable to
these 5,461 existing master meter
operators, saving 141,986 hours of
burden annually.
Affected Public: Natural Gas Pipeline
Operators.
Annual Reporting and Recordkeeping
Burden:
Total Annual Responses: 3,882.
Total Annual Burden Hours: 723,192.
Frequency of Collection: On occasion.
4. Title: Gas Distribution Annual
Report.
OMB Control Number: 2137–0629.
Current Expiration Date: 10/31/2021.
Abstract: The PSR require distribution
operators to prepare and submit annual
reports with summary information on
their pipeline infrastructure. PHMSA
proposed to shift the mechanical fitting
failure form requirements to a count of
hazardous leaks involving a failure of a
mechanical joint on the distribution
annual report form. PHMSA estimates
that it will take gas distribution
operators approximately 30 minutes (0.5
hours; calculated as 13,075 mechanical
joint failures divided by 1,446 operators
times 3 minutes per mechanical joint
failure) to add this information to the
annual report. As a result, the burden
for this information collection will
increase by approximately 723 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: 25,305.
Frequency of Collection: Annually.
I. Unfunded Mandates Reform Act of
1995
Unfunded Mandates Reform Act (2
U.S.C. 1501 et seq.) requires agencies to
assess the effects of Federal regulatory
actions on State, local, and Tribal
governments, and the private sector. For
any NPRM or final rule 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 1996 dollars 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.
PHMSA prepared a final RIA and
determined that this final rule does not
impose enforceable duties on State,
local, or Tribal governments or on the
private sector of $164 million in 2019
dollars or more in any one year. A copy
of the final RIA is available for review
in the docket of this rulemaking.
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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 crossreference for this action to the Unified
Agenda.
List of Subjects
49 CFR Part 191
Pipeline reporting requirements,
Integrity management, Pipeline safety,
Gas gathering.
49 CFR Part 192
Incorporation by reference, Pipeline
safety, Fire prevention, Security
measures.
In consideration of the forgoing,
PHMSA is amending 49 CFR parts 191
and 192 as follows:
PART 191—TRANSPORTATION OF
NATURAL AND OTHER GAS BY
PIPELINE; ANNUAL REPORTS,
INCIDENT REPORTS, AND SAFETYRELATED CONDITION REPORTS
1. The authority citation for 49 CFR
part 191 continues to read as follows:
■
Authority: 30 U.S.C. 185(w)(3), 49 U.S.C.
5121, 60101 et seq., and 49 CFR 1.97
2. In § 191.3, in the definition of
‘‘Incident’’ revise paragraph (1)(ii) to
read as follows:
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■
§ 191.3
Definitions.
*
*
*
*
*
Incident means any of the following
events:
(1) * * *
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(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. For
adjustments for inflation observed in
calendar year 2021 onwards, changes to
the reporting threshold will be posted
on PHMSA’s website. These changes
will be determined in accordance with
the procedures in appendix A to part
191.
*
*
*
*
*
■ 3. In § 191.11, revise paragraph (b) to
read as follows:
§ 191.11
Report.
Distribution system: Annual
*
*
*
*
*
(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 a production
pipeline or a gathering line other than
a regulated gathering line as determined
in § 192.8.
§ 191.12
[Removed and Reserved]
4. Remove and reserve § 191.12.
5. Appendix A to part 191 is added to
read as follows:
■
■
Appendix A to Part 191—Procedure for
Determining Reporting Threshold
I. Property Damage Threshold Formula
Each year after calendar year 2021, the
Administrator will publish a notice on
PHMSA’s website announcing the updates to
the property damage threshold criterion that
will take effect on July 1 of that year and will
remain in effect until the June 30 of the next
year. The property damage threshold used in
the definition of an Incident at § 191.3 shall
be determined in accordance with the
following formula:
Where:
Tr is the revised damage threshold,
Tp is the previous damage threshold,
CPIr is the average Consumer Price Indices
for all Urban Consumers (CPI–U)
published by the Bureau of Labor
Statistics each month during the most
recent complete calendar year, and
CPIp is the average CPI–U for the calendar
year used to establish the previous
property damage criteria.
PART 192—TRANSPORTATION OF
NATURAL GAS AND OTHER GAS BY
PIPELINE: MINIMUM FEDERAL
SAFETY STANDARDS
5. The authority citation for 49 CFR
part 192 continues to read as follows:
■
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Authority: 30 U.S.C. 185(w)(3), 49 U.S.C.
5103, 60101 et seq., and 49 CFR 1.97.
6. In § 192.7:
a. Revise paragraph (a), paragraph (b)
introductory text, and paragraph (b)(9);
■ b. Remove and reserve paragraph
(c)(7); and
■ c. Revise paragraph (e) introductory
text and paragraphs (e)(11) and (20).
The revisions read as follows:
■
■
§ 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. The materials listed in this
section have the full force of law. 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 fedreg.legal@
nara.gov or go to www.archives.gov/
federal-register/cfr/ibr-locations.html.
(b) American Petroleum Institute
(API), 200 Massachusetts Ave. NW,
Suite 1100, Washington, DC 20001, and
phone: 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
§§ 192.225(a); 192.227(a); 192.229(b)
and (c); 192.241(c); and Item II,
Appendix B.
*
*
*
*
*
(e) ASTM International (formerly
American Society for Testing and
Materials), 100 Barr Harbor Drive, PO
Box C700, West Conshohocken, PA
19428, phone: (610) 832–9585, website:
https://astm.org.
*
*
*
*
*
(11) 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,’’
approved February 1, 2019, (ASTM
E:\FR\FM\11JAR6.SGM
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ER11JA21.019
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 rule in
accordance with NEPA, NEPA
implementing regulations (40 CFR parts
1500–1508), and DOT Order 5610.1C.
PHMSA prepared a draft environmental
assessment (EA) for the NPRM and
posted it in the rulemaking docket;
PHMSA received no comments on the
draft EA. For this final rule, PHMSA has
prepared a Final Environmental
Assessment (EA) and has determined
that this final rule will not significantly
affect the quality of the human
environment. The final EA for this final
rule is available in the docket.
2237
2238
Federal Register / Vol. 86, No. 6 / Monday, January 11, 2021 / Rules and Regulations
F2620), IBR approved for §§ 192.281(c)
and 192.285(b).
*
*
*
*
*
■ 7. In § 192.121:
■ 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’’;
b. In paragraph (c)(2) introductory text
add the words ‘‘on or’’ after the word
‘‘produced’’;
■ c. Revise paragraphs (c)(2)(iii) and
(iv), and (d)(2)(iv);
■ d. In paragraph (e) introductory text
add the words ‘‘on or’’ after the word
‘‘produced’’; and
■ e. Revise paragraph (e)(4).
The revisions read as follows:
■
§ 192.121
Design of plastic pipe.
*
*
*
*
*
(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
thickness
(inches)
Pipe size
(inches)
⁄ ″ CTS ...................................................................................................................................................................
⁄ ″ IPS .....................................................................................................................................................................
3⁄4″ CTS ...................................................................................................................................................................
3⁄4″ IPS .....................................................................................................................................................................
1″ CTS .....................................................................................................................................................................
1″ IPS ......................................................................................................................................................................
11⁄4″ IPS ...................................................................................................................................................................
11⁄2″ IPS ...................................................................................................................................................................
2″ .............................................................................................................................................................................
3″ .............................................................................................................................................................................
4″ .............................................................................................................................................................................
6″ .............................................................................................................................................................................
8″ .............................................................................................................................................................................
10″ ...........................................................................................................................................................................
12″ ...........................................................................................................................................................................
16″ ...........................................................................................................................................................................
18″ ...........................................................................................................................................................................
20″ ...........................................................................................................................................................................
22″ ...........................................................................................................................................................................
24″ ...........................................................................................................................................................................
12
12
(d) * * *
(2) * * *
(iv) The minimum wall thickness for
a given outside diameter is not less than
Corresponding
SDR
(values)
0.090
0.090
0.090
0.095
0.099
0.119
0.151
0.173
0.216
0.259
0.265
0.315
0.411
0.512
0.607
0.762
0.857
0.952
1.048
1.143
7
9.3
9.7
11
11
11
11
11
11
13.5
17
21
21
21
21
21
21
21
21
21
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
thickness
(inches)
Pipe size
(inches)
⁄ ″ CTS ...................................................................................................................................................................
⁄ ″ IPS .....................................................................................................................................................................
3⁄4″ CTS ...................................................................................................................................................................
3⁄4″ IPS .....................................................................................................................................................................
1″ CTS .....................................................................................................................................................................
1″ IPS ......................................................................................................................................................................
11⁄4 IPS ....................................................................................................................................................................
11⁄2″ IPS ...................................................................................................................................................................
2″ IPS ......................................................................................................................................................................
3″ IPS ......................................................................................................................................................................
4″ IPS ......................................................................................................................................................................
6″ IPS ......................................................................................................................................................................
12
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12
(e) * * *
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(4) The minimum wall thickness for a
given outside diameter is not less than
that listed in table 3 to paragraph (e)(4).
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0.090
0.090
0.090
0.095
0.099
0.119
0.151
0.173
0.216
0.259
0.333
0.491
Corresponding
SDR
(values)
7.0
9.3
9.7
11
11
11
11
11
11
13.5
13.5
13.5
Federal Register / Vol. 86, No. 6 / Monday, January 11, 2021 / Rules and Regulations
2239
TABLE 3 TO PARAGRAPH (e)(4)
PA–12 pipe: minimum wall thickness and SDR values
Minimum wall
thickness
(inches)
Pipe size
(inches)
⁄ ″ CTS ...................................................................................................................................................................
⁄ ″ IPS .....................................................................................................................................................................
⁄ ″ CTS ...................................................................................................................................................................
3⁄4″ IPS .....................................................................................................................................................................
1″ CTS .....................................................................................................................................................................
1″ IPS ......................................................................................................................................................................
11⁄4″ IPS ...................................................................................................................................................................
11⁄2″ IPS ...................................................................................................................................................................
2″ IPS ......................................................................................................................................................................
3″ IPS ......................................................................................................................................................................
4″ IPS ......................................................................................................................................................................
6″ IPS ......................................................................................................................................................................
12
12
34
*
*
*
*
*
8. In § 192.153 revise paragraphs (b)
and paragraph (e) to read as follows:
■
§ 192.153
welding.
Components fabricated by
jbell on DSKJLSW7X2PROD with RULES6
*
*
*
*
*
(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 § 192.7),
except for the following:
(1) Regularly manufactured buttwelding fittings.
(2) Pipe that has been produced and
tested under a specification listed in
appendix B to this part.
(3) Partial assemblies such as split
rings or collars.
(4) Prefabricated units that the
manufacturer certifies have been tested
to at least twice the maximum pressure
to which they will be subjected under
the anticipated operating conditions.
*
*
*
*
*
(e) The test requirements for a
prefabricated unit or pressure vessel,
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) A prefabricated unit or pressure
vessel installed after July 14, 2004 is not
subject to the strength testing
requirements at § 192.505(b) provided
the component has been 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) A prefabricated unit or pressure
vessel must be tested for a duration
specified as follows:
(i) A prefabricated unit or pressure
vessel installed after July 14, 2004, but
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before October 1, 2021 is exempt from
§§ 192.505(c) and (d) and 192.507(c)
provided it has been tested for a
duration consistent with the ASME
BPVC requirements referenced in
paragraph (a) or (b) of this section.
(ii) A prefabricated unit or pressure
vessel installed on or after October 1,
2021 must be tested for the duration
specified in either § 192.505(c) or (d),
§ 192.507(c), or § 192.509(a), whichever
is applicable for the pipeline in which
the component is being installed.
(3) For any prefabricated unit or
pressure vessel permanently or
temporarily installed on a pipeline
facility, an operator must either:
(i) Test the prefabricated unit or
pressure vessel in accordance with this
section and Subpart J of this part after
it has been placed on its support
structure at its final installation
location. The test may be performed
before or after it has been tied-in to the
pipeline. Test records that meet
§ 192.517(a) must be kept for the
operational life of the prefabricated unit
or pressure vessel; or
(ii) For a prefabricated unit or
pressure vessel that is pressure tested
prior to installation or where a
manufacturer’s pressure test is used in
accordance with paragraph (e) of this
section, inspect the prefabricated unit or
pressure vessel after it has been placed
on its support structure at its final
installation location and confirm that
the prefabricated unit or pressure vessel
was not damaged during any prior
operation, transportation, or installation
into the pipeline. The inspection
procedure and documented inspection
must include visual inspection for
vessel damage, including, at a
minimum, inlets, outlets, and lifting
locations. Injurious defects that are an
integrity threat may include dents,
gouges, bending, corrosion, and
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0.090
0.090
0.090
0.095
0.099
0.119
0.151
0.173
0.216
0.259
0.333
0.491
Corresponding
SDR
(values)
7
9.3
9.7
11
11
11
11
11
11
13.5
13.5
13.5
cracking. This inspection must be
performed prior to operation but may be
performed either before or after it has
been tied-in to the pipeline. If injurious
defects that are an integrity threat are
found, the prefabricated unit or pressure
vessel must be either non-destructively
tested, re-pressure tested, or remediated
in accordance with applicable part 192
requirements for a fabricated unit or
with the applicable ASME BPVC
requirements referenced in paragraphs
(a) or (b) of this section. Test,
inspection, and repair records for the
fabricated unit or pressure vessel must
be kept for the operational life of the
component. Test records must meet the
requirements in § 192.517(a).
(4) An initial pressure test from the
prefabricated unit or pressure vessel
manufacturer may be used to meet the
requirements of this section with the
following conditions:
(i) The prefabricated unit or pressure
vessel is newly-manufactured and
installed on or after October 1, 2021,
except as provided in paragraph
(e)(4)(ii) of this section.
(ii) An initial pressure test from the
fabricated unit or pressure vessel
manufacturer or other prior test of a new
or existing prefabricated unit or
pressure vessel may be used for a
component that is temporarily installed
in a pipeline facility in order to
complete a testing, integrity assessment,
repair, odorization, or emergency
response-related task, including noise or
pollution abatement. The temporary
component must be promptly removed
after that task is completed. If
operational and environmental
constraints require leaving a temporary
prefabricated unit or pressure vessel
under this paragraph in place for longer
than 30 days, the operator must notify
PHMSA and State or local pipeline
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safety authorities, as applicable, in
accordance with § 192.18.
(iii) The manufacturer’s pressure test
must meet the minimum requirements
of this part; and
(iv) The operator inspects and
remediates the prefabricated unit or
pressure vessel after installation in
accordance with paragraph (e)(3)(ii) of
this section.
(5) An existing prefabricated unit or
pressure vessel that is temporarily
removed from a pipeline facility to
complete a testing, integrity assessment,
repair, odorization, or emergency
response-related task, including noise or
pollution abatement, and then reinstalled at the same location must be
inspected in accordance with paragraph
(e)(3)(ii) of this section; however, a new
pressure test is not required provided no
damage or threats to the operational
integrity of the prefabricated unit or
pressure vessel were identified during
the inspection and the MAOP of the
pipeline is not increased.
(6) Except as provided in paragraphs
(e)(4)(ii) and (5) of this section, on or
after October 1, 2021, an existing
prefabricated unit or pressure vessel
relocated and operated at a different
location must meet the requirements of
this part and the following:
(i) The prefabricated unit or pressure
vessel must be designed and
constructed in accordance with the
requirements of this part at the time the
vessel is returned to operational service
at the new location; and
(ii) The prefabricated unit or pressure
vessel must be pressure tested by the
operator in accordance with the testing
and inspection requirements of this part
applicable to newly installed
prefabricated units and pressure vessels.
■ 9. In § 192.229, revise paragraph (b) to
read as follows:
§ 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
jbell on DSKJLSW7X2PROD with RULES6
*
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 § 192.7)
within the preceding 71⁄2 months.
*
*
*
*
*
■ 10. In § 192.281, revise paragraph (c)
to read as follow:
§ 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 § 192.7), or
an alternative written procedure that
has been demonstrated to provide an
equivalent or superior level of safety
and has been proven by test or
experience to produce strong gastight
joints, and the following:
*
*
*
*
*
■ 11. In § 192.283 revise paragraph
(a)(3) to read as follows:
§ 192.283 Plastic pipe: Qualifying joining
procedures.
(a) * * *
(3) For procedures intended for nonlateral 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.
*
*
*
*
*
■ 12. In § 192.285, revise paragraph (b)
to read as follows
§ 192.285 Plastic pipe: Qualifying persons
to make joints.
*
*
*
*
*
(b) The specimen joint must be:
(1) Visually examined during and
after assembly or joining and found to
have the same appearance as a joint or
photographs of a joint that is acceptable
under the procedure; and
(2) In the case of a heat fusion, solvent
cement, or adhesive joint:
(i) Tested under any one of the test
methods listed under § 192.283(a), and
for PE heat fusion joints (except for
electrofusion joints) visually inspected
in accordance with ASTM F2620
(incorporated by reference, see § 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;
(ii) Examined by ultrasonic inspection
and found not to contain flaws that
would cause failure; or
(iii) Cut into at least 3 longitudinal
straps, each of which is:
(A) Visually examined and found not
to contain voids or discontinuities on
the cut surfaces of the joint area; and
(B) Deformed by bending, torque, or
impact, and if failure occurs, it must not
initiate in the joint area.
*
*
*
*
*
■ 13. In § 192.465, revise paragraph (b)
to read as follows:
§ 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
21⁄2 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) After January 1, 2022, each
remotely inspected rectifier must be
physically inspected for continued safe
and reliable operation at least once each
calendar year, but with intervals not
exceeding 15 months.
*
*
*
*
*
■ 14. In § 192.481, revise paragraph (a)
and add paragraph (d) to read as
follows:
§ 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:
Pipeline type:
Then the frequency of inspection is:
(1) Onshore other than a Service Line ....................................................
At least once every 3 calendar years, but with intervals not exceeding
39 months.
At least once every 5 calendar years, but with intervals not exceeding
63 months, except as provided in paragraph (d) of this section.
At least once each calendar year, but with intervals not exceeding 15
months.
(2) Onshore Service Line .........................................................................
(3) Offshore ..............................................................................................
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*
*
*
*
*
(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, but with
intervals not exceeding 39 months.
■ 15. In 192.491, revise paragraph (c) to
read as follows:
§ 192.491
192.475(b) for as long as the pipeline
remains in service.
(2) Operators must retain records of
the two most recent atmospheric
corrosion inspections for each
distribution service line that is being
inspected under the interval in
§ 192.481(a)(2).
16. In § 192.505, revise paragraph (c)
to read as follows
■
Corrosion control records.
*
*
*
*
*
(c) Each operator shall maintain a
record of each test, survey, or inspection
required by this subpart in sufficient
detail to demonstrate the adequacy of
corrosion control measures or that a
corrosive condition does not exist.
These records must be retained for at
least 5 years with the following
exceptions:
(1) Operators must retain records
related to §§ 192.465(a) and (e) and
§ 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 mai ntaining the
pressure at or above the test pressure for
at least 8 hours.
*
*
*
*
*
2241
17. In § 192.507, add paragraph (d) to
read as follows:
■
§ 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 preinstallation hydrostatic pressure test
must be conducted in accordance with
the requirements of this section.
■ 18. In § 192.619, revise Table 1 to
paragraph (a)(2)(ii) to read as follows:
§ 192.619 Maximum allowable operating
pressure: Steel or plastic pipelines.
*
*
*
(a) * * *
(2) * * *
(ii) * * *
*
*
TABLE 1 TO PARAGRAPH (a)(2)(ii)
Factors,1 2 segment—
Installed before
(Nov. 12, 1970)
Class location
1
2
3
4
.......................................................................................................
.......................................................................................................
.......................................................................................................
.......................................................................................................
Installed after
(Nov. 11, 1970)
and before
July 1, 2020
1.1
1.25
1.4
1.4
Installed on or
after July 1, 2020
Converted under
§ 192.14
1.25
1.25
1.5
1.5
1.25
1.25
1.5
1.5
1.1
1.25
1.5
1.5
jbell on DSKJLSW7X2PROD with RULES6
1 For offshore pipeline segments installed, uprated or converted after July 31, 1977, that are not located on an offshore platform, the factor is
1.25. For pipeline segments installed, uprated or converted after July 31, 1977, that are located on an offshore platform or on a platform in inland
navigable waters, including a pipe riser, the factor is 1.5.
2 For a component with a design pressure established in accordance with § 192.153(a) or (b) installed after July 14, 2004, the factor is 1.3.
■
19. In § 192.740, revise the section
heading, paragraph (a) and paragraph (c)
to read as follows:
pipeline other than a regulated
gathering line as determined in § 192.8
of this part.
§ 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 as
determined in § 192.8 that is not
operated as part of a distribution
system.
*
*
*
*
*
(c) This section does not apply to
equipment installed on:
(1) A service line that only serves
engines that power irrigation pumps;
(2) A service line included in a
distribution integrity management plan
meeting the requirements of subpart P of
this part; or
(3) A service line directly connected
to either a production or gathering
(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 line or a
gathering line other than a regulated
onshore gathering line as determined in
§ 192.8;
(2) Individual service lines directly
connected to either a transmission or
regulated gathering pipeline and
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20. Revise § 192.1003 to read as
follows:
§ 192.1003 What do the regulations in this
subpart cover?
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maintained in accordance with
§ 192.740(a) and (b); and
(3) Master meter systems.
■ 21. In § 192.1005, revise the section
heading to read as follows:
§ 192.1005 What must a gas distribution
operator (other than a small LPG operator)
do to implement this subpart?
*
*
*
*
*
22. In § 192.1007, revise paragraph (b)
to read as follows:
■
§ 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.
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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.
*
*
*
*
*
§ 192.1009
[Removed and Reserved]
23. Remove and reserve § 192.1009.
■ 24. In § 192.1015, revise the section
heading, and paragraphs (a) and (b) to
read as follows:
■
§ 192.1015 What must a small LPG
operator do to implement this subpart?
jbell on DSKJLSW7X2PROD with RULES6
(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) Elements. A written integrity
management plan must address, at a
minimum, the following elements:
(1) Knowledge. The operator must
demonstrate knowledge of its pipeline,
which, to the extent known, should
include the approximate location and
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material of its pipeline. The operator
must identify additional information
needed and provide a plan for gaining
knowledge over time through normal
activities conducted on the pipeline (for
example, design, construction,
operations or maintenance activities).
(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.
(3) Rank risks. The operator must
evaluate the risks to its pipeline and
estimate the relative importance of each
identified threat.
(4) Identify and implement measures
to mitigate risks. The operator must
determine and implement measures
designed to reduce the risks from failure
of its pipeline.
(5) Measure performance, monitor
results, and evaluate effectiveness. The
operator must monitor, as a performance
measure, the number of leaks eliminated
or repaired on its pipeline and their
causes.
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(6) Periodic evaluation and
improvement. The operator must
determine the appropriate period for
conducting IM program evaluations
based on the complexity of its pipeline
and changes in factors affecting the risk
of failure. An operator must re-evaluate
its entire program at least every 5 years.
The operator must consider the results
of the performance monitoring in these
evaluations.
*
*
*
*
*
Appendix B to Part 192 [Amended]
25. Amend Appendix B to part 192 as
follows:
■ a. In section I.A., remove the entry for
‘‘ASTM D2513–12ae1’’ and add in its
place a new entry for ‘‘ASTM D2513’’,
and
■ b. In Section I.B., remove the entry for
‘‘ASTM D2513–12ae1’’ and add in its
place a new entry for ‘‘ASTM D2513’’.
■
Issued in Washington, DC, on January 1,
2021, under authority delegated in 49 CFR
1.97.
Howard R. Elliott,
Administrator.
[FR Doc. 2021–00208 Filed 1–8–21; 8:45 am]
BILLING CODE 4910–60–P
E:\FR\FM\11JAR6.SGM
11JAR6
Agencies
[Federal Register Volume 86, Number 6 (Monday, January 11, 2021)]
[Rules and Regulations]
[Pages 2210-2242]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2021-00208]
[[Page 2209]]
Vol. 86
Monday,
No. 6
January 11, 2021
Part VI
Department of Transportation
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Pipeline and Hazardous Materials Safety Administration
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49 CFR Parts 191 and 192
Pipeline Safety: Gas Pipeline Regulatory Reform; Final Rule
Federal Register / Vol. 86 , No. 6 / Monday, January 11, 2021 / Rules
and Regulations
[[Page 2210]]
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DEPARTMENT OF TRANSPORTATION
Pipeline and Hazardous Materials Safety Administration
49 CFR Parts 191 and 192
[Docket No. PHMSA-2018-0046; Amdt Nos. 191-29; 192-128]
RIN 2137-AF36
Pipeline Safety: Gas Pipeline Regulatory Reform
AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA),
DOT.
ACTION: Final rule; withdrawal of enforcement discretion.
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SUMMARY: PHMSA is amending the Federal Pipeline Safety Regulations to
ease regulatory burdens on the construction, maintenance, and operation
of gas transmission, distribution, and gathering pipeline systems
without adversely affecting safety. The amendments in this rule are
based on rulemaking petitions from stakeholders, and DOT and PHMSA
initiatives to identify appropriate areas where regulations might be
repealed, replaced, or modified, and PHMSA's review of public comments.
PHMSA also, as of the effective date of this final rule, withdraws the
March 29, 2019 ``Exercise of Enforcement Discretion Regarding Farm
Taps'' and the unpublished October 27, 2015 letter to the Interstate
Natural Gas Association of America announcing a stay of enforcement
pertaining to certain pressure vessels.
DATES: Effective Date: This rule is effective March 12, 2021.
Incorporation by reference date: The incorporation by reference of
certain publications listed in the rule is approved by the Director of
the Federal Register as of March 12, 2021.
Voluntary compliance date: March 12, 2021.
Delayed compliance date: Compliance with the amendments adopted in
the rule is required beginning October 1, 2021.
Enforcement discretion withdrawal date: The withdrawal of 84 FR
11253 (Mar. 26, 2019) is effective as of March 12, 2021.
FOR FURTHER INFORMATION CONTACT: Sayler Palabrica, Transportation
Specialist, by telephone at 202-366-0559.
SUPPLEMENTARY INFORMATION:
I. Executive Summary
II. Background
III. Analysis of Comments, GPAC Recommendations, and PHMSA's
Response
IV. Availability of Standards Incorporated by Reference
V. Regulatory Analyses and Notices
I. Executive Summary
A. Purpose of This Deregulatory Action
PHMSA is amending the Federal Pipeline Safety Regulations (PSR) at
49 CFR parts 191 and 192 to ease regulatory burdens on the
construction, operation, and maintenance of gas transmission,
distribution, and gathering pipeline systems without adversely
affecting safety. These amendments include regulatory relief actions
identified by internal agency review, petitions for rulemaking, and
public comments submitted in response to a Department of Transportation
(DOT) regulatory reform notice entitled ``Notification of Regulatory
Review.'' \1\
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\1\ 82 FR 45750 (Oct. 2, 2017).
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On June 9, 2020, PHMSA published a notice of proposed rulemaking
(NPRM) to seek public comments on proposed changes to the PSR.\2\ A
summary of those proposed changes, and PHMSA's response to stakeholder
feedback on the individual provisions, is provided below in section III
(Analysis of Comments, GPAC Recommendations, and PHMSA's Response).
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\2\ 85 FR 35240.
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B. Summary of PSR Amendments
The final rule makes the following amendments to 49 CFR parts 191
and 192:
A. Revision of certain requirements (at Sec. Sec. 191.11, 192.740,
and 192.1003) pertaining to farm taps giving operators the choice of
managing inspections of pressure regulators serving farm taps under
either their distribution integrity management plan (DIMP) or by
following the inspection requirements at Sec. 192.740;
B. Revision of certain requirements (at Sec. Sec. 192.1003,
192.1005 and 192.1015) pertaining to master meter systems to exempt
operators of these simple pipeline facilities from DIMP requirements
that had been designed with complex distribution systems in mind;
C. Revision of certain reporting requirements (at Sec. Sec. 191.12
and 192.1009) to eliminate a dedicated report form for mechanical
fitting failures (MFFs), and modify other required report forms to
incorporate more information on MFFs;
D. Revision of the monetary threshold for incident reporting (at
Sec. 191.3) to update for inflation over the three decades since the
current monetary threshold was established, and introduce a new
appendix A to part 191 to provide for annual updates to that threshold
to account for inflation;
E. Revision of Sec. 192.465 to clarify that operators may remotely
inspect rectifier stations for external corrosion;
F. Revision of atmospheric corrosion monitoring requirements (at
Sec. Sec. 192.481, 192.491, 192.1007, and 192.1015) both to align the
inspection interval for atmospheric corrosion on gas distribution
service pipelines with leakage survey requirements at Sec. 192.723,
and to clarify that consideration of corrosion risks under DIMP
explicitly includes atmospheric corrosion;
G. Revision of requirements governing plastic pipe (at Sec. Sec.
192.7, 192.121, 192.281, 192.285, and appendix B to part 192) to
improve alignment with, and incorporate by reference, certain updated
industry standards;
H. Revision of test requirements for pressure vessels at Sec.
192.153 to align pressure test factor requirements with industry
standards, and to clarify certain other pressure testing requirements;
I. Revision of the welding process requirement at Sec. 192.229 to
align better with welder requalification requirement at Sec.
192.229(d)(2); and
J. Revision of language at Sec. 192.507 to extend an existing
authorization for pre-testing of fabricated units and short segments of
steel pipe prior to installation on pipelines with high-stress
operating conditions to pipelines operating at lower-stress operating
conditions.
C. Costs and Benefits
In accordance with 49 U.S.C. 60102, Executive Order (E.O.)
12866,\3\ and DOT regulations at Sec. 5.13(e), PHMSA has prepared an
assessment of the costs and benefits of this final rule as well as
reasonable alternatives. The amendments promulgated in this final rule
are deregulatory, with the intention and effect of reducing regulatory
burdens, increasing flexibility, improving efficiency, and adding
clarity to existing rules without adversely affecting safety. PHMSA
expects the incremental cost savings to accrue on an ongoing annual
basis. PHMSA used a 20-year analysis period for this final rule. PHMSA
estimates the total quantified annualized cost savings to be
approximately $129.8 million (at a discount rate of 7 percent) or
approximately $132.5 million (at a discount rate of 3 percent). Table-1
presents the estimated total cost savings for the 20-year period and
the estimated
[[Page 2211]]
annualized cost savings over the same period.
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\3\ ``Regulatory Planning and Review,'' 58 FR 51735 (Oct. 4,
1993).
Table 1--Total Estimated Discounted Cost Savings
[2019 $ in millions]
------------------------------------------------------------------------
Estimated cost
Category savings
------------------------------------------------------------------------
Total (20 years; discounted at 7 percent)............. $1,374.8
Total (20 years; discounted at 3 percent.............. 1,971
Annualized (discounted at 7 percent).................. 129.8
Annualized (discounted at 3 percent).................. 132.5
------------------------------------------------------------------------
PHMSA does not anticipate that the amendments will have an adverse
impact on safety or a significant effect on the environment. The
largest quantified cost savings are due to the PSR amendments related
to farm taps and atmospheric corrosion discussed in sections III.A and
III.F, respectively, of the preamble to this final rule. PHMSA expects
other amendments to improve regulatory flexibility, clarity, and
simplicity. Additional details regarding PHMSA's evaluation of the
costs and benefits of this final rule are available in the Final
Regulatory Impact Analysis (RIA) posted in the rulemaking docket.
II. Background
A. Regulatory Reform Executive Orders and Department Response
As explained at greater length in the NPRM,\4\ DOT published a
notice, ``Notification of Regulatory Review,'' on October 2, 2017,\5\
requesting recommendations on existing DOT rules and other agency
actions that could be eliminated without adversely affecting safety.
DOT in particular solicited the public's assistance in identifying DOT
regulations and other actions which eliminate jobs or inhibit job
creation; are outdated, unnecessary, or ineffective; impose costs that
exceed benefits; create a serious inconsistency or otherwise interfere
with regulatory reform initiatives and policies; could be revised to
use performance standards in lieu of design standards; or that
potentially unnecessarily encumber energy production. After a 30-day
comment period, DOT re-opened the comment period until December 1,
2017.\6\ DOT received nearly 3,000 public comments. Approximately 30
pertained to the PSR.\7\
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\4\ 85 FR 35241-42.
\5\ 82 FR 45750.
\6\ 82 FR 51178.
\7\ Docket No. DOT-OST-2017-0069.
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B. PHMSA Notice of Proposed Rulemaking
Consistent with DOT's regulatory reform efforts and informed by
PSR-pertinent comments received in response to the DOT Notification of
Regulatory Review discussed above, PHMSA's Office of Pipeline Safety
(OPS) reviewed the PSR and identified unnecessary, outdated, and non-
cost-justified regulatory requirements that could be repealed,
replaced, or modified without adversely affecting safety. PHMSA also
considered certain petitions for rulemaking and petitions for
reconsideration of earlier PSR amendments.
On June 9, 2020, PHMSA published an NPRM \8\ proposing several
amendments to 49 CFR parts 191 and 192 to reduce regulatory burdens on
operators of gas pipelines without adversely affecting safety. The
comment period for the NPRM ended on August 10, 2020. PHMSA received 46
comments on the NPRM, including late-filed comments. PHMSA received
comments from groups representing the regulated pipeline industry;
groups representing various public interests, including environmental
groups; State utility commissions and regulators; individual pipeline
operators; and private citizens. PHMSA received late-filed comments
from the National Association of State Pipeline Safety Representatives
(NAPSR), the Gas Piping Technology Committee (GPTC), a coalition of
several industry trade associations, and GPA Midstream.\9\ PHMSA also
had a conversation with a member of the Gas Pipeline Advisory Committee
(GPAC) and representatives of the Pipeline Safety Trust (PST) after the
end of the comment period; a summary of that meeting has been placed in
the rulemaking docket. Consistent with Sec. Sec. 5.13(i)(5) and
190.323, PHMSA considered the late-filed comments and materials because
of their relevance to the rulemaking and the absence of additional
expense or delay resulting from their consideration.
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\8\ 85 FR 35240.
\9\ GPA, formerly the Gas Processors Association.
---------------------------------------------------------------------------
Some of the comments PHMSA received were beyond the scope of the
amendments proposed in the NPRM. The issues raised in those comments
may be the subject of other existing or future rulemaking proceedings.
The remaining comments reflect a wide variety of views on the
merits of the proposed PSR amendments. PHMSA read and considered all
the comments posted to the docket for this rulemaking. These comments
and PHMSA's response to those comments are described in section III.
Contemporaneously with PHMSA's development of the NPRM, the
President issued E.O. 13924, ``Regulatory Relief to Support Economic
Recovery,'' \10\ directing Federal agencies to respond to the economic
harm caused by the novel coronavirus by reviewing their regulations and
considering taking appropriate action, consistent with applicable law,
to temporarily or permanently rescind or modify those regulations to
reduce regulatory burdens and thereby promote economic growth.\11\
PHMSA understands the cost savings expected from this final rule to be
consistent with E.O. 13924's mandate.
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\10\ 85 FR 31353 (May 22, 2020).
\11\ E.O. 13924 at Sec. 4.
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C. Gas Pipeline Advisory Committee Meeting
The Technical Pipeline Safety Standards Committee, commonly known
as the Gas Pipeline Advisory Committee (GPAC; the committee), is an
advisory committee mandated by statute (49 U.S.C. 60115) that advises
PHMSA on proposed safety standards. The GPAC is one of two pipeline
advisory committees that focus on technical safety standards that were
established under the Federal Advisory Committee Act, as amended (5
U.S.C. App. 1-16). The GPAC consists of 15 members, with membership
divided among Federal and State agencies, the natural gas industry,
[[Page 2212]]
and the public. The GPAC considers the ``technical feasibility,
reasonableness, cost-effectiveness, and practicability'' of each
proposed pipeline safety standard and provides PHMSA with recommended
actions pertaining to those proposals.
The GPAC met in an online virtual meeting on October 7, 2020 to
consider the regulatory proposals of the NPRM. The GPAC members
discussed comments made on the NPRM. To assist the GPAC in its
deliberations, PHMSA presented a description and summary of the
proposals in the NPRM and the comments received on those issues. PHMSA
also assisted the committee by fostering discussion, developing
recommendations, and providing direction on which issues were most
pressing. A transcript of the meeting and all presented materials is
available in the docket for the rulemaking and on the web page PHMSA
established for the meeting.\12\
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\12\ https://primis.phmsa.dot.gov/meetings/MtgHome.mtg?mtg=151&nocache=4862.
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The committee voted on the technical feasibility, reasonableness,
cost-effectiveness, and practicability of each of the NPRM's
provisions. In many instances, the committee recommended changes that
the committee found would make certain proposals more feasible,
reasonable, cost-effective, or practicable. These balloted
recommendations and the transcript for the meeting serve as the GPAC's
report pursuant to 49 U.S.C. 60115. These recommendations are discussed
in section III of the preamble to this final rule for each of the
topics proposed in the NPRM.
III. Analysis of Comments, GPAC Recommendations, and PHMSA's Response
The proposals in the NPRM, substantive comments received, as well
as the GPAC's recommendations are organized by topic below and are
discussed in the appropriate section with PHMSA's response to and
resolution of those comments.
Distribution Integrity Management Program (DIMP)
On December 4, 2009, PHMSA issued a final rule titled, ``Pipeline
Safety: Integrity Management Program for Gas Distribution Pipelines.''
\13\ The 2009 rule created 49 CFR part 192, subpart P, requiring gas
distribution operators to develop and implement integrity management
(IM) programs. The NPRM contained two proposed revisions to DIMP
requirements to ease or eliminate regulatory burdens on certain gas
distribution operators. The first revision is to allow operators of
farm taps \14\ connected to transmission or regulated gathering lines
the option of managing maintenance of pressure regulating devices under
either Sec. 192.740 or their DIMP in accordance with subpart P. As
part of this amendment, PHMSA also proposed to 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, the NPRM included a proposal to revise Sec. Sec.
192.1003 and 192.1015 to exempt master meter operators from DIMP due to
their simplicity. Master meter systems that serve fewer than 100
customers from a single source are currently required to comply with a
simplified set of DIMP requirements detailed in Sec. 192.1015.
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\13\ 74 FR 63905.
\14\ A ``farm tap'' is the common name for a pipeline directly
connected to a gas transmission, production, or gathering pipeline
that provides gas to a customer. The term farm tap is not defined in
the PSR; however, portions of a farm tap upstream of 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 Sec. 192.3 (definition of ``service
line'').
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A. Farm Taps (Sections 191.11, 192.740, 192.1003)
1. PHMSA's Proposal
In the NPRM, PHMSA proposed 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.
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.'' \15\ 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). Currently, such
devices must be inspected and tested at least once every 3 calendar
years, with intervals not to exceed 39 months. The 2017 rule also
revised the DIMP applicability regulations at Sec. 192.1003 to exclude
farm taps from DIMP requirements. The change was intended to create
uniform compliance requirements for farm taps, address over-
pressurization risks, and decrease the burden of meeting the DIMP
requirements for transmission and gathering line operators who
otherwise do not operate distribution assets. However, PHMSA had not
considered that some farm taps are operated by local distribution
companies rather than the operator of the transmission, gathering or
production line itself. Operators who historically had included farm
taps in their DIMP found it burdensome to remove those facilities from
their plan and reevaluate the risks under a new, prescriptive program.
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\15\ 82 FR 7972.
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DOT received a comment in response to the Notification of
Regulatory Review 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, the
NPRM proposed to revise Sec. Sec. 192.740 and 192.1003 to exempt farm
taps originating from transmission lines and regulated gathering lines
from Sec. 192.740 if they are included in a DIMP under subpart P. This
provides operators the choice to manage the safety of farm tap
regulators under either DIMP or the Sec. 192.740 inspection
requirement.
Finally, the NPRM included a proposal to exempt farm tap service
lines connected to 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 at Sec. 192.3 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 service line connected to a production pipeline must have an
operator identification number in accordance with Sec. 191.22 and must
submit gas distribution incident reports for incidents that occur on
the service line (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.
2. Summary of Public Comments
Several commenters suggested PHMSA should simplify how farm tap
requirements are presented in the PSR. The American Association of
Laboratory
[[Page 2213]]
Accreditation (A2LA) recommend adding a provision requiring that those
entities conducting inspections achieve and maintain ISO/IEC 17020
(Conformity Assessment-Requirements for the Operation of Various Types
of Bodies Performing Inspection) accreditation. The FreedomWorks
Foundation (FreedomWorks) commented that the proposed changes in the
NPRM would especially benefit smaller operations burdened by the high
cost of compliance upon startup. PST commented the proposed PSR
amendments appear to demonstrate an equivalent level of safety and they
do not oppose this change. One company provided an editorial suggestion
that the last word in proposed Sec. 192.740(c)(3) should be ``or'' to
clarify that this section (Sec. 192.740) does not apply if any one of
the listed conditions apply.
Several commenters commented on farm tap-related terms and
definitions proposed in Sec. 192.740. Sander Resources suggested there
were at least two significant definitional issues contained within the
proposed rule that confused farm tap operators. The first relates to
``unregulated . . . gathering.'' Sander Resources commented that,
technically, there is no such thing as ``unregulated gathering.'' All
gathering lines are subject to the jurisdiction of PHMSA, but some are
exempted from the requirements of part 192 as specified in Sec. 192.9.
Thus, this reference could be interpreted to mean that all gathering
lines are still subject to the requirements of Sec. 192.740 or Sec.
192.1003 and related provisions, which could encompass much of part
192. They recommended that PHMSA clarify what it means to be
``unregulated,'' possibly through a reference to whether a line is
subject to regulation under Sec. 192.9. The Gas Piping Technology
Committee (GPTC) similarly suggested that PHMSA clarify that regulated
and unregulated gathering lines are as determined in Sec. 192.8.
Sander Resources (on behalf of the Independent Petroleum
Association of America, or IPAA) also raised a concern related to the
definition of ``service line'' and, in particular, language in the
NPRM's preamble suggesting that the part 192-regulated ``service line''
portion of a farm tap would begin at the ``first aboveground point
where downstream piping can be isolated from source piping (e.g., a
valve or regulator inlet).'' AGA, API, the American Public Gas
Association (APGA), and INGAA (collectively, AGA et al.) jointly
submitted a similar comment recommending against PHMSA defining the
``service line'' portion of a farm tap in the proposed amendment to
Sec. 192.740. They commented it is neither practicable nor necessary
for safety to define a uniform starting point for the service line on
every farm tap directly connected to a transmission line. Their
preferred approach would be to incorporate a distribution center
definition that allows farm tap piping to be classified as a
distribution center and explicitly allow operators to designate piping
as transmission, even if the pipeline could be classified as
distribution under the existing Sec. 192.3. Rather than defining where
the ``service line'' starts for farm taps under part 192, TC Energy
commented PHMSA should revise Sec. 192.740 to apply to ``pipelines''
serving farm tap customers instead of ``service lines,'' and eliminate
the description of the source of supply to the farm tap customer. TC
Energy believes that these changes would maintain the intended
protections to farm tap customers and address industry concerns. A
private citizen similarly commented that, in addition to these
clarifications, PHMSA should clarify the definitions for transmission
lines and distribution centers.
GPA Midstream stated that they did not support the NPRM preamble
statement that, on a farm tap, the boundary between source piping and
the distribution service lines is the first aboveground isolation point
downstream from the source piping. They stated that there is no legal
basis for using that point to delineate where a source production,
gathering, or transmission line ends and a gas distribution service
line under part 192 begins in a farm tap configuration. GPA Midstream
urged PHMSA to acknowledge in the final rule that an operator may
exercise reasonable discretion in determining where source piping ends
and distribution service line piping, if any, begins in farm tap
configurations. The Independent Oil and Gas Association of West
Virginia (IOGAWV) commented PHMSA should not attempt to use its
authority to change private contracts by transferring the cost of
complying with the PSR to producers and unregulated gathering line
operators. IOGAWV and the Ohio Oil and Gas Association (OOGA) stated
PHMSA should take this opportunity to exempt farm taps from the PSR.
IPAA urged PHMSA to recognize the significant difference between
privately-owned farm taps, governed by contract or statute, and true
distribution systems. GPA Midstream reiterated concerns with the
definition of the start of a service line and the applicability of part
192 to farm taps connected to production lines and unregulated
gathering lines in supplemental comments submitted after the GPAC
meeting.
The GPAC voted unanimously in favor of the PSR amendments proposed
in the NPRM, provided that PHMSA remove Sec. 192.740(c)(4), thus
eliminating language implying where a service line starts on a farm
tap.
3. PHMSA Response
The final rule adopts the amendments with respect to farm taps as
proposed in the NPRM, but revises the proposed Sec. 192.740 as
discussed below. PHMSA determined that compliance with the pressure
regulator inspection requirements in Sec. 192.740 or compliance with
DIMP provide an equivalent level of safety. DIMP does not include
specific, prescriptive inspection requirements for pressure regulating
devices; however, operators are required by Sec. 192.1007 to evaluate
risks due to equipment failure under DIMP, which includes pressure
regulating devices. Accordingly, farm tap operators must consider
overpressure risk due to regulator failure in their DIMP, especially if
the source pipeline pressure is very high. While Sec. 192.740 is
focused on pressure regulator maintenance, DIMP is a broader safety
program that requires operators identify, evaluate, rank, and mitigate
a wide range of risks to pipeline safety. Either requirement provides
safety to farm tap customers by reducing the probability of a regulator
system malfunction and, in the case of DIMP, incidents caused by other
threats such as excavation damage and corrosion. Therefore, this change
provides greater flexibility for operators of these farm taps while
still requiring that operators evaluate all equipment to protect
against failures and protect human health and the physical environment.
This proposed amendment was intended to provide flexibility for
farm tap operators. It was not designed to resolve more general
definitional questions surrounding the topic of farm taps. Therefore,
PHMSA agrees with the suggestion to remove the proposed Sec.
192.740(c)(4) from the final rule, which implied where the source
piping on a farm tap ends and distribution, transmission, or customer
piping begins. PHMSA believes that this change resolves most of the
concerns about definitional changes raised by commenters. To the extent
that there are remaining questions surrounding farm taps following this
rulemaking, PHMSA will use ongoing efforts such as the proposed Farm
Taps Frequently Asked
[[Page 2214]]
Questions (FAQs); \16\ the remaining rulemaking projects associated
with the Safety of Gas Transmission and Gas Gathering Pipelines NPRM;
\17\ and, if necessary, additional rulemaking and guidance. While the
comment from TC Energy sidesteps these definitional issues, and has the
benefit of extending protection to farm taps that operate at greater
than 20 percent of specified minimum yield strength (SMYS) (and are
therefore classified as transmission lines rather than service lines
pursuant to the definition of a transmission line in Sec. 192.3), it
requires defining an additional term (``farm tap customer'') which was
not made available for public comment in the NPRM or discussed by other
comments in the rulemaking docket.
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\16\ 85 FR 21820 (Apr. 20, 2020).
\17\ RINs 2137-AF39 (Pipeline Safety: Safety of Gas Gathering
Pipelines) and 2137-AF38 (Pipeline Safety: Safety of Gas
Transmission Pipelines, Repair Criteria, Integrity Management
Improvements, Cathodic Protection, Management of Change, and Other
Related Amendments), associated with PHMSA, ``Notice of Proposed
Rulemaking: ``Pipeline Safety--Safety of Gas Transmission and
Gathering Pipelines,'' 81 FR 20721 (Apr. 8, 2016).
---------------------------------------------------------------------------
While this final rule does not define the boundaries of that
portion of a farm tap that is regulated as a service line under part
192, the fact that a farm tap may include a regulated service line
remains unchanged. Therefore, PHMSA disagrees with comments that the
NPRM's characterization of portions of farm taps as jurisdictional
service lines creates ``entirely new'' legal obligations for operators
of service lines who also operate non-jurisdictional production lines
and rural gathering lines that are not subject to safety regulation
under part 192. Removing farm taps connected to production lines and
unregulated gathering lines from the scope of the entire PSR, as
suggested by some commenters, would be a consequential change from
longstanding regulatory application and is beyond the scope of this
final rule.
PHMSA and its predecessor agencies have been explicit and
consistent with respect to the applicability of the part 192
regulations to distribution service lines in farm tap applications
since the earliest years of Federal gas pipeline safety oversight. The
Office of Pipeline Safety revised the definition of a service line in
Sec. 192.3 to clarify the point at which a service line ends and
customer piping begins in an NPRM entitled, ``Minimum Federal Safety
Standards for Transportation of Natural and Other Gas by Pipeline:
Definition of Service Line,'' published on April 10, 1971.\18\ On April
10, 1973, PHMSA finalized the proposal and defined the downstream end
of a service line as the customer meter or connection to customer
piping, whichever is further downstream.\19\ This boundary stands with
minor clarifications to this day at Sec. 192.3. PHMSA formulated the
definition of ``service line'' to address service lines in farm tap
applications and other situations where no meter is present. PHMSA's
predecessor agency, the Research and Special Programs Administration,
again acknowledged the regulated status of service lines in farm tap
applications in a final rule titled, ``Pipeline Safety: Customer-Owned
Service Lines'' issued on August 14, 1995.\20\ Finally, providing gas
to farm tap customers is not a defined gathering or production function
in either Sec. 192.3 or in API Recommended Practice (RP) 80
(incorporated by reference in Sec. 192.7). While production pipelines
and some gathering pipelines are not subject to safety regulation under
part 192, the distribution of national gas to customers is subject to
PHMSA jurisdiction (49 U.S.C. 60101(a)(21)(i)) and the applicability of
part 192 (Sec. Sec. 192.1(a), 192.3) regardless of other activities in
which an operator may also be engaged.
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\18\ 36 FR 9667.
\19\ 38 FR 9083.
\20\ 60 FR 41821.
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Regarding operators' concerns about their responsibility for
customer-owned piping that they do not own or have access to, PHMSA
reiterates that the final rule imposes no new requirements on operators
of service lines in farm tap applications. Section 192.3 provides that
a service line ends at the connection to customer-owned piping, or the
outlet of the meter, whichever is further downstream. In the preamble
to the 1995 customer-owned service line rule described above, PHMSA
explained that that the PSR applies to the distribution of gas up to
the end of a pipeline operator's service line.\21\ In an earlier
interpretation, PHMSA also noted that customer piping downstream of the
end of a service line as defined in Sec. 192.3 is not subject to part
192, provided the gas is for the customer's own use.\22\ Therefore, the
PSR does not require the source pipeline operator to maintain customer-
owned piping downstream of the customer meter as defined in Sec.
192.3. If there is no customer meter, then the service line terminates
at the connection to customer-owned piping. Some operators do maintain
customer piping voluntarily or as required by State, local, or
contractual requirements. If an operator of a service line does not
maintain the customer's piping under such arrangement, then the
customer notification requirements in Sec. 192.16 may apply.
---------------------------------------------------------------------------
\21\ 60 FR 41821.
\22\ PHMSA Interpretation #PI-73-0110 (June 6, 1973), https://cms7.phmsa.dot.gov/regulations/title49/interp/PI-73-0110.
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PHMSA agrees with certain comments to clarify language in Sec.
192.740. In the final rule, PHMSA has replaced the term ``unregulated
gathering line'' with a gathering line other than a regulated gathering
line as determined in Sec. 192.8. In other words, a gathering line as
determined in accordance with Sec. 192.8 and API RP 80, but excluding
a Type A or Type B regulated gathering line as defined in Sec. 192.8.
In addition, the exceptions in paragraph (c) are now separated by an
``or'' in the final rule.
Lastly, because the PSR revisions adopted in this final rule
obviate the need for its March 29, 2019 ``Exercise of Enforcement
Discretion Regarding Farm Taps,'' \23\ PHMSA withdraws that document as
of the effective date of this final rule.
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\23\ 84 FR 11253.
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B. Master Meter Operators (Sections 192.1003, 192.1005, 192.1015)
1. PHMSA's Proposal
In the NPRM, PHMSA proposed to revise Sec. Sec. 192.1003,
192.1005, 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 meter systems include
owners of apartment complexes or mobile home parks who provide or sell
gas to tenants. Unlike most gas distribution operators, delivering gas
is typically not a master meter operator's primary business.
When DIMP requirements were first proposed in 2008,\24\ 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
DIMP requirements that master meter operators could easily implement
and that would enhance safety. However, PHMSA has determined that
Section 192.1015 requirements are neither easily implemented nor do
they enhance safety. Master meter operators have struggled to implement
the relatively simple master meter systems DIMP requirements that were
designed for
[[Page 2215]]
complex gas distribution systems. In addition, PHMSA determined that
there is no safety benefit from applying even that limited set of DIMP
requirements to master meter systems, as compliance with other
applicable pipeline safety regulations in part 192 provides robust
assurance of public safety. The applicable part 192 requirements that
PHMSA considered include, but are not limited to, operations and
maintenance requirements at subpart L and subpart M, continuing
surveillance requirements at Sec. 192.613, and the failure
investigation requirement at Sec. 192.617.
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\24\ PHMSA, ``Notice of Proposed Rulemaking: Integrity
Management Program for Gas Distribution Pipelines,'' 73 FR 36015
(June 25, 2008) (DIMP NPRM).
---------------------------------------------------------------------------
2. Summary of Public Comments
Several commenters generally supported exempting master meter
operators from the DIMP requirements in part 192. These commenters
(including the National Propane Gas Association (NPGA), the National
Association of Pipeline Safety Representatives (NAPSR), AmeriGas, and
Superior Plus Propane (SPP)) agreed with PHMSA's characterization of
master meter systems as generally small, simple systems that see little
benefit from DIMP compliance. These commenters agreed that compliance
with existing subparts A through N of part 192 is sufficient to ensure
the safety of small, simple master meter systems. They asserted that
the current requirement of subpart P to create a DIMP, even using the
SHRIMP tool,\25\ consumes significant additional time and resources
with little or no safety benefit, noting that the result of the process
for master meter systems is typically a determination that there is no
need for additional mitigating actions on any portion of the pipeline
system. As a result, the commenters stated that the time and resources
expended to comply with the DIMP requirements have no meaningful safety
benefits for such systems. The PST commented that they do not oppose
this change, but urged PHMSA and its State partners to ensure that
master meter operators are managing the integrity risks to their
systems outside the context of a DIMP.
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\25\ The ``Simple, Handy, Risk-based Integrity Management Plan''
tool published by the APGA Security and Integrity Foundation.
---------------------------------------------------------------------------
PHMSA also received comments concerning similar DIMP requirements
for small liquefied petroleum gas (LPG) distribution pipeline systems.
A ``small LPG operator'' is defined in Sec. 192.1001 as a liquefied
petroleum gas distribution system that serves fewer than 100 customers
from a single source. Small LPG operators are currently required to
comply with the same DIMP requirements as master meter systems. Several
commenters (including NPGA, NAPSR, AmeriGas, and SPP) commented that
jurisdictional propane pipeline systems are like master meter systems
and therefore small LPG operators should be exempt from the DIMP
requirements as well. They commented that small LPG systems are
comparable to master meter systems in size and application. Like master
meter systems, the commenters claimed the majority of small LPG
pipeline systems are single-property systems that occupy a small
overall footprint in size, generally operate at a single operating
pressure, and have no equipment other than pipe, meters, regulators,
and valves. They commented that small LPG systems typically serve 25
customers or less, and facilities such as those at RV parks or strip
malls can have as few as three customers; very few small LPG systems
serve more than 100 customers. One anonymous commenter associated with
an LPG system stated that the DIMP process is lengthy and unnecessary,
and that in their experience, many of the prompts on the DIMP form \26\
do not make sense given the layout of a small LPG utility. NAPSR stated
that many of these smaller systems identify only third-party damage as
a major threat to the system, and a DIMP requires a considerable amount
of work for a very small amount of safety benefit.
---------------------------------------------------------------------------
\26\ PHMSA Gas Distribution Integrity Assessment Question Set,
available at https://www.phmsa.dot.gov/forms/phmsa-gas-distribution-ia-question-set-pdf.
---------------------------------------------------------------------------
Commenters representing LPG suppliers (including AmeriGas, SPP, and
NPGA) noted that with regard to the PSR, the regulated entity is the
entity that owns the pipeline and receives the operator ID issued by
PHMSA for that pipeline system. They stated that in many cases, the LPG
supplier does not operate the pipeline and their primary business is to
transport gas by delivery truck, not pipelines. They further stated
that most are contractors to the entity that owns the pipeline and the
pipeline operator ID for the system. They stated that many of these
master meter operators use contractors for service, but those
contractors are not the operators under part 192. These commenters
agreed that the other part 192 requirements continue to apply to
provide adequate requirements for small LPG systems in the absence of
DIMP requirements. They also stated that in addition to the
requirements in part 192 applicable to all gas distribution pipelines,
Sec. 192.11 requires LPG distribution systems to comply with a
National Fire Protection Association (NFPA) standard, NFPA 58 (LP-Gas
Code) or NFPA 59 (Utility LP-Gas Plant Code), which contains comparable
and supplemental provisions that address safety. They asserted that the
additional requirements of DIMP do not add a measure of safety beyond
the provisions in part 192 and NFPA 58.
AmeriGas and NPGA estimated that extending the NPRM's proposed DIMP
exemptions for master meters to small LPG systems could result in $1.12
million in annualized cost savings; this estimate was calculated by
applying the cost estimates in the RIA to an estimate of the number of
small LPG operators in Safety Regulation for Small LPG Distribution
Systems, a report published in 2018 by the Transportation Research
Board (TRB).\27\ The commenters asserted that these additional savings
would further PHMSA's goal of reducing regulatory impact burdens. The
commenters also stated that these estimated savings to the industry
would allow small LPG operators to devote more of their resources in
other areas of safety.
---------------------------------------------------------------------------
\27\ TRB, Transportation Research Board Special Report 327:
Safety Regulation for Small LPG Distribution Systems (2018), https://www.nap.edu/catalog/25245/safety-regulation-for-small-lpg-distribution-systems.
---------------------------------------------------------------------------
NAPSR suggested that small distribution utilities with 100 or fewer
customers should also be exempted from the DIMP requirements, stating
that many master meter systems, small distribution systems and small
LPG systems typically have no threats beyond the minimum threats listed
in Sec. 192.1015(b)(2).
The GPAC voted unanimously in favor of PHMSA's proposed amendment
with respect to the applicability of DIMP requirements to master meter
systems. The GPAC did not recommend changes to DIMP requirements for
small LPG systems or small distribution systems.
3. PHMSA Response
The final rule revises Sec. Sec. 192.1003, 192.1005, and 192.1015
to eliminate DIMP requirements for master meter systems as proposed in
the NPRM. 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 State
inspection and operator maintenance effort was being used to improve
DIMP compliance among master meter operators. Despite these
[[Page 2216]]
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 may be better used to implement other part 192 safety
requirements effectively that master meter system operators will remain
obliged to follow.
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
DIMP NPRM 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
comprehensive management system like DIMP is not required to integrate
data and information to identify risk mitigation strategies and
actions. PHMSA's experience indicates that the analysis and
documentation requirements of DIMP have had little safety benefit for
this type of operator. And, anecdotally, PHMSA and State enforcement
personnel have advised that focusing on more fundamental risk
mitigation activities (particularly those required by Sec. Sec.
192.605 (Procedural manual for operations, maintenance, and
emergencies), 192.613 (Continuing surveillance), and 192.617
(Investigations of failures)) yields 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. Considering the burden on finite State inspection
resources, implementation difficulties, and the limited safety benefits
of DIMP compliance for master meter systems described above, PHMSA
believes there could even be potential safety benefits because
operators and inspectors can prioritize more pertinent compliance
activities specific to master meter systems.
PHMSA appreciates the comments regarding the applicability of DIMP
towards small LPG operators and acknowledges that many small LPG
systems have configurations like master meter systems. However, PHMSA
believes that the decision about whether to extend the DIMP exception
to such facilities or to all distribution systems with fewer than 100
customers would benefit from additional safety analysis and notice and
comment procedures prior to further consideration. In 2018, the TRB
published a report on Federal safety standard for small LPG systems.
The TRB's recommendations focused on clarifying the definition of a
``public place'' and improving State inspection programs. While the TRB
suggested that a PHMSA-supervised State waiver process could be
appropriate, it did not recommend exempting all small LPG systems from
DIMP or any other requirement. PHMSA will continue to evaluate the
issue of DIMP requirements for small LPG systems and, if appropriate,
propose changes in a future rulemaking giving due consideration to the
public comments on the NPRM, the recommendations of the GPAC, and the
TRB report. For similar reasons, PHMSA has also not adopted suggestions
from commenters to exempt other distribution operators with fewer than
100 customers.
Reporting and Information Collections
C. Mechanical Fitting Failure Reporting (Sections 191.12, 192.1009)
1. PHMSA's Proposal
On February 1, 2011, PHMSA issued the final rule, ``Pipeline
Safety: Mechanical Fitting Failure Reporting Requirements'' \28\ adding
Sec. Sec. 191.12, 192.1001, and 192.1009 to the PSR. Section 191.12
sets forth the requirement for operators to report mechanical fitting
failures (MFFs) through DOT Form PHMSA F-7100.1-2 (MFF report form).
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 joint, the
majority of which are low-consequence or no-consequence events that do
not meet the definition of an incident at Sec. 191.3. These
requirements expanded an earlier requirement established in the
December 4, 2009 DIMP final rule that was limited to mechanical
couplings used to join plastic pipe.\29\ The DIMP final rule adopted
the MFF report requirement as a result of investigations of incidents
caused by poorly designed or improperly installed mechanical joints
throughout the pipeline industry. PHMSA initially sought to collect
these data in 2011 to determine the frequency of mechanical joint
failures and identify the most common characteristics of those
failures.\30\ The 2009 DIMP final rule was part of a broader effort by
PHMSA and the gas distribution pipeline industry to identify potential
safety issues with plastic gas pipelines.
---------------------------------------------------------------------------
\28\ 76 FR 5494.
\29\ 74 FR 63905.
\30\ 76 FR 5495.
---------------------------------------------------------------------------
Like the Gas Distribution Incident Report form,\31\ the MFF report
form requires operators submit information on the design and
installation of the failed fitting and the apparent cause of the
failure. The MFF report form also includes manufacturing information;
however, this is generally not known by the operator and therefore is
reported as ``unknown.'' MFF reports are required for any failure of a
mechanical joint other than those that result in a ``non-hazardous
leak,'' as opposed to Gas Distribution Incident Reports, which are
required only for events that meet the criteria for reportable
``incidents'' in Sec. 191.3. Operators report any ``hazardous leak''
as that term is defined at Sec. 192.1001. The criteria for a
``hazardous leak'' does not depend on an outcome severity threshold.
Approximately 15,000 MFF reports are submitted to PHMSA each year,
compared to approximately 100 Gas Distribution Incident Reports due to
all causes. PHMSA publishes a report on the information collected and
its analysis of the information received annually, which is available
online.\32\
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\31\ DOT Form PHMSA F 7100.1.
\32\ https://www.phmsa.dot.gov/pipeline/gas-distribution-integrity-management/dimp-performance-measures-data-analysis-procedure-report.
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PHMSA determined that further collection of MFF reports has limited
value, and proposed to remove Sec. Sec. 191.12 and 192.1009,
eliminating the requirement for operators to submit MFF reports through
DOT Form PHMSA F-7100.1-2. PHMSA understands from analyzing MFF report
forms received over the last decade that the purposes of this reporting
requirement have been realized: PHMSA's analysis of data from MFF
reports confirmed its expectations regarding MFF characteristics and
causes, and pipeline operators have become much more sensitive to MFFs.
PHMSA considered that operators would still be required to submit
incident reports via a modified version of the Gas Distribution
Incident Report form (which would include most of the information on
the MFF report form) for releases from mechanical fittings that meet
the definition of an incident at Sec. 191.3. Part G5-5 of the Gas
Distribution Incident Report form currently requires operators to
identify the MFF report number for incidents involving an MFF; PHMSA
therefore proposed to replace this cross-reference
[[Page 2217]]
with the fitting, manufacturer, and failure information that is
currently collected on the MFF report form. PHMSA also proposed to
revise the Gas Distribution Annual Report form \33\ to include a count
of hazardous leaks involving a mechanical joint failure. This issue was
raised in comments submitted in response to the DOT Notification of
Regulatory Review from the Associations, the Gas Piping Technology
Committee (GPTC), and the West Virginia Oil and Natural Gas Association
(WVONGA), which identified the MFF reporting requirement as an
unnecessary and burdensome information collection.
---------------------------------------------------------------------------
\33\ DOT Form PHMSA F 7100.1-1.
---------------------------------------------------------------------------
2. Summary of Public Comments
Several commenters (including AmeriGas, NPGA, SPP, Dresser Natural
Gas Solutions, the Norton McMurray Manufacturing Company (NORMAC),
Oleksa and Associates, the Plastics Pipe Institute (PPI), and a private
citizen) supported eliminating the MFF reporting requirement. Dresser
contended that PHMSA has found these data do not provide meaningful
trends related to risk of pipeline leaks. PPI stated that the removal
of this regulatory reporting burden reduces the unnecessary focus on
mechanical fittings as a potential source of incidents. NORMAC agreed
that MFF reporting has not provided statistically significant trends or
information upon which operators or regulators can act.
Several commenters (including AmeriGas, SPP, and NPGA) expressed
concerns regarding PHMSA's proposal to modify the Gas Distribution
Annual Report form to collect data on the number of mechanical joint
failures. Those commenters opposed including a count of leaks involving
mechanical joints on the Gas Distribution Annual Report form, noting
that if limited value was derived from independent MFF reporting, it is
reasonable to conclude that there would be limited value in tracking
and reporting the number of MFFs on revised Gas Distribution Annual and
Incident Report forms. NORMAC commented that part C of the current Gas
Distribution Annual Report form requires each operator to report the
total number of leaks and how many were classified as hazardous based
upon the cause of the leak. The instructions provided for completion of
part C describe each classification of cause in detail in terms of what
is being requested of an operator. NORMAC noted that modifying the Gas
Distribution Annual Report form as proposed will lead the user to jump
to the conclusion that any leak involving a mechanical joint arises
from the mechanical fitting being ``faulty,'' when the leak may be
caused by improper installation by the operator and should therefore be
coded as caused by ``Incorrect Operation.'' GPTC commented that
reporting leaks caused by mechanical joint failure would repeat
reporting of leaks caused by ``pipe, weld, or joint failure'' and
potentially be confusing for operators. They further commented that the
leak information is intended to be general in nature and not intended
to capture the ``laboratory analysis'' for eliminated leaks.
Regarding the proposed changes to Gas Distribution Incident Report
form, NORMAC expressed concerns with the NPRM's proposal to incorporate
existing data fields in the current MFF report within part G (Apparent
Cause), sub-cause G5 (Pipe, Weld, or Joint Failure) of a revised Gas
Distribution Incident Report form. NORMAC noted that the cause of a
failure may not be due to Pipe, Weld, or Joint Failure. Specifically,
they noted that fittings that fail due to improper installation are
required to be categorized under the ``Incorrect Operation'' cause.
NORMAC also mentioned that Question 12 under sub-cause G5 (Pipe, Weld,
or Joint Failure) duplicate what sub-cause G7 (Incorrect Operation) is
asking. NORMAC stated that requiring respondents to answer the same
question under two categories will lead to confusion and make effective
analysis of the resulting database difficult. NORMAC submitted text
revisions to sub-cause G5 of the Gas Distribution Incident Report form
and associated instructions.
Dresser raised similar concerns with both the Gas Distribution
Annual Report and the Gas Distribution Incident Report forms, in
addition to noting that there could be confusion concerning the
difference between a mechanical fitting and a mechanical joint. Dresser
noted that the existing categories support the reporting of pipeline
failures where mechanical fittings may be involved under the existing
categories of ``Weld Pipe or Joint Failure'' or ``Incorrect Operation''
depending on the causal factors being a manufacturing or design defect
for the former or a deficiency in the field installation practice or
improper application for the latter. NORMAC also supported addressing
the distinction between ``mechanical fitting'' and ``joint'' to ensure
that the regulatory oversight activity focus on joints, the making of
joints, and the qualifying of joining procedures.
Theresa Pugh Consulting commented that PHMSA should revise the Gas
Distribution Incident Report form to include whether industrial and
power sector customers were notified of a curtailment in gas supply
following an incident and the duration of such disruption. The
commenter stated the form should allow the operator to state if gas
supply was maintained by re-directing natural gas at full contracted
capacity to the customer through reverse flow or through alternative
parties. The commenter noted that the power and industrial customers
would benefit from a way to determine during contract negotiations
whether the company they wish to purchase gas from has a sound and
reliable safety program, but acknowledged challenges with ensuring that
such information is not in a format that could be used by competitors
to reverse engineer operational information about industrial customers
such as plastics manufacturing plants. The commenter recommended that
PHMSA should expand rather than shrink the reporting measures on its
reporting forms.
NORMAC commented that burden on operators can be drastically
reduced beyond what the proposed rulemaking proposes by also
eliminating the portion of Plastic Pipe Database Collection (PPDC)
reporting conducted by the American Gas Association that deals with
mechanical joints. NORMAC commented that the PPDC is nearly identical
to the MFF and has also not shown useful trends. NORMAC also asserted
that recording and reporting mechanical joint leaks through PPDC is not
as effective as addressing the problem directly within each operator's
IM program. NORMAC suggested that PHMSA propose the discontinuation of
this reporting effort in its role as PPDC chair.
PST opposed eliminating the MFF report requirement. They questioned
whether this would prevent PHMSA from becoming aware of thousands of
MFFs per year, many of which result in hazardous and potentially
explosive leaks, others of which result in non-explosive but hazardous
leaks of methane into the atmosphere. The commenter stated these
circumstances would also not typically be reported as a safety-related
condition, because of the many exemptions and exceptions to the safety-
related condition reports listed in Sec. 191.23(b). PST asserted the
detailed information on MFFs is currently gathered so that PHMSA can
identify any patterns among those failures, either by geography or
failure type or any other common parameter. Limiting the detailed
reporting in the MFF report to reportable incidents eliminates another
source of
[[Page 2218]]
information of leading indicators of problems common among operators,
one that nets information on 15,000 fitting failures each year.
The GPAC voted 13-2 in favor of PHMSA's proposed amendment to
eliminate the MFF reporting requirement. PST and the Environmental
Defense Fund (EDF) voted against the proposed amendment. During the
GPAC discussions, PST reiterated its reservations regarding reducing
the availability to PHMSA and other safety regulators of information on
hazardous leaks. PST also opined that eliminating MFF reporting may
reduce operators' incentives to improve mechanical fitting performance.
EDF, meanwhile, contended that the MFF report data being eliminated
could prove helpful to Federal and State environmental regulators and
public service commissions in evaluating the significance of methane
emissions from service line couplings.
3. PHMSA Response
In the final rule, PHMSA is adopting the amendments to MFF
reporting requirements at Sec. Sec. 191.12 and 192.1001 as proposed in
the NPRM. PHMSA is also retaining the proposed requirement to include a
count of MFFs on the Gas Distribution Annual Report form and revision
of the Gas Distribution Incident Report form to include information
from the MFF report for incidents involving a failure of a mechanical
joint.
PHMSA's 2018 analysis of MFF data reports obtained to date confirm
PHMSA's expectations regarding the frequency and characteristics
(including material, type, location, and vintage of fittings) of MFFs
when it began this information collection activity under the DIMP final
rule.\34\ The 2018 analysis further notes that the MFF reports
submitted in the preceding year show similar trends to the previous 5
years, and that all changes were within the expected variance. These
findings mirror the conclusions of PHMSA's earlier, 2016 analysis of
the MFF reports submitted in the then-preceding 5 years (2011-
2015).\35\ Because MFF report data reviewed in 2018 and 2016 confirmed
PHMSA's expectations regarding the frequency and characteristics of
mechanical joint failure without yielding new statistically significant
causal or predictive insights, PHMSA has determined that additional
information collection via a dedicated MFF report form is unnecessary.
---------------------------------------------------------------------------
\34\ PHMSA, Analysis of Data from Required Reporting of
Mechanical Fitting Failures that Result in a Hazardous Leak (Sec.
192.1009) at 47-48 (Jul. 4, 2018), https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/gas-distribution-integrity-management/66046/mffr-data-analysis-procedure-2017-data-report-final-07-04-2018.pdf.
\35\ PHMSA, Analysis of Data from Required Reporting of
Mechanical Fitting Failures that Result in a Hazardous Leaks (Sec.
192.1009) (Oct. 15, 2016).
---------------------------------------------------------------------------
PHMSA further notes improvements in fitting design, operator
joining practices, and Federal safety requirements since the
introduction of the MFF reporting requirement have improved the safety
of mechanical fittings on newer installations. PHMSA's 2018 analysis of
MFF report data reached a similar conclusion, noting that many operator
DIMPs are sensitive to the risk of MFF following the introduction of
the MFF reporting requirement. However, PHMSA's 2018 analysis notes
that the number of operators submitting MFF reports has stayed
approximately the same for the last several years--suggesting that any
action-forcing benefit hypothesized has been realized and that the
benefits from continuing a dedicated MFF reporting requirement may be
negligible.
The modifications to other reports adopted in this final rule will
help PHMSA ensure continued availability of information needed to
provide effective regulatory oversight of MFFs. Leaks from mechanical
joints are already aggregated within the broader categories on the
existing Gas Distribution Annual Report form. The revised Gas
Distribution Annual Report form requires reporting the number of leaks
involving mechanical joint failures in addition to the existing,
aggregated categories. This change is expected to provide sufficient
information to track the safety performance of mechanical joints over
time, among operators, or across the industry. These data are expected
to provide operators, PHMSA, and State inspectors sufficient
information to identify if action is needed under DIMP or other
elements of operator programs for compliance with part 192
requirements.
PHMSA is also revising the Gas Distribution Annual Report form to
identify the number of leaks involving a mechanical joint failure as a
separate line item from the count of leaks by cause. However, to
address the potential confusion raised by commenters, PHMSA will revise
the proposed part C of the Gas Distribution Annual Report form to
clarify that operators should report the number of hazardous leaks
``involving'' a mechanical joint failure, rather than ``caused'' by a
mechanical joint failure. This aligns with the language in the current
MFF report requirement and is clearer. PHMSA will further clarify in
the form instructions that the count of leaks involving a mechanical
joint failure is separate and in addition to the leaks by cause.
Operators should continue to report all leaks by cause in the table in
part C of the Gas Distribution Annual Report form as they have been
doing previously, while the new count at the end of part C consists of
a count of hazardous leaks involving the failure of a mechanical joint
regardless of whether the leak was caused by equipment failure,
incorrect operation/installation, or other causes. Likewise, on the Gas
Distribution Incident Report form, operators should continue to report
incidents involving a failure of a mechanical joint that was caused by
improper installation under the ``incorrect operation'' cause under
section G7 of the Gas Distribution Incident Report form. The revised
Gas Distribution Incident Report form will not require operators to
submit design and manufacturing information about incidents involving
mechanical joints that were caused by incorrect operation rather than
material, weld, or equipment failure.
PHMSA appreciates the concerns raised by commenters and members of
the GPAC about reducing the data available to PHMSA and other
stakeholders through changes in reporting requirements proposed in the
NPRM and adopted in this final rule. PHMSA agrees that access to
quality safety-related information is critical to implementation of an
effective regulatory and enforcement program. However, these safety
programs benefit from the flexibility both to create targeted
information collection activities to address safety issues and to
remove those information collection activities that are no longer
necessary or have not proven useful. Here, PHMSA has determined that
its original purpose for introducing a dedicated MFF reporting
requirement has been satisfied. Although PHMSA could posit new
justifications (e.g., use by environmental regulators and utility
commissions in calibrating regulatory oversight of service line
couplings) for this dedicated reporting requirement, it declines to do
so in this rulemaking. Nevertheless, PHMSA submits that Federal and
State regulators' oversight activities may continue to benefit from
nearly a decade of historical, granular data obtained from MFF
reports,\36\ in addition to the operator-specific MFF data that PHMSA
will collect in the Gas
[[Page 2219]]
Distribution Annual and Incident Report forms modified by this final
rule.
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\36\ PHMSA makes such raw data available on its website at
https://www.phmsa.dot.gov/data-and-statistics/pipeline/mechanical-fitting-failure-data-gas-distribution-operators.
---------------------------------------------------------------------------
Replacing the full MFF report with a count of MFFs on the Gas
Distribution Annual Report results in a reduction in reporting burden
for each event but without a significant loss of useful information to
operators and PHMSA. Although the revised requirements eliminate the
detailed information on each mechanical fitting failure, this
information has not yielded meaningful new causal or predictive
insights regarding leaks involving mechanical joints. On the other
hand, the general count of leaks involving a mechanical joint failure
as required in the revised Gas Distribution Annual Report is not
burdensome to compile yet provides information on the relative safety
performance of mechanical joints in general. This information remains
valuable to PHMSA and State agencies for safety performance monitoring
and for prioritizing inspections. PHMSA has determined that incident
reporting requirements via a revised Gas Distribution Incident Report
form and the revision to the Gas Distribution Annual Report form to
include a count of hazardous leaks involving a mechanical joint failure
is sufficient to identify the total number of hazardous leaks involving
mechanical joint failures and identify trends over time and among
States or operators.
Nor does this change absolve operators of other safety requirements
that apply when leaks at MFFs are discovered. PHMSA requires that gas
pipeline operators have procedures for investigating failures under
Sec. 192.617 to determine the causes of the failure and minimize the
possibility of a recurrence. PHMSA also requires operators repair
hazardous leaks promptly under Sec. 192.703. These requirements apply
regardless of whether the failure results in a reportable leak or
incident. Finally, operators are required to consider leak history
under the continuing surveillance requirements at Sec. 192.613 and
under their DIMP (Sec. 192.1007(b), (d), and (e)). PHMSA accordingly
finds that the PSR change adopted in this final rule eliminates an
unnecessary reporting burden without an adverse impact on safety.
Many of the comments received pertained to related topics on the
Gas Distribution Incident and Annual Report forms and are not directly
related to the reporting of mechanical joint failures. PHMSA will
consider these comments during periodic updates and renewals of these
information collections pursuant to the Paperwork Reduction Act. PHMSA
does not have authority over voluntary information collection organized
by other, non-governmental entities and therefore the comment related
to data collected by the AGA through the PPDC is outside the scope of
the NPRM. However, PHMSA will consider raising with other members of
the PPDC whether its reporting protocols for MFFs should be modified.
D. Monetary Threshold for Incident Reporting (Section 191.3, New
Appendix A to Part 191)
1. PHMSA's Proposal
On May 3, 1984, PHMSA's predecessor agency, the Research and
Special Programs Administration, added a definition for an ``incident''
at Sec. 191.3.\37\ The definition provides criteria that requires
operators to report specific events to PHMSA. The 1984 definition of an
incident consists of a release of gas that, among other things, results
in estimated property damage of $50,000 or more. That monetary
threshold includes losses to the operator and third parties but
excludes the cost of any lost gas. Today, over 30 years later,
operators must still notify the National Response Center (Sec. 191.5)
and submit an incident report to PHMSA (Sec. Sec. 191.9 and 191.15)
for any release that results in estimated property damage to the
operator or third parties of $50,000 or more.
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\37\ 49 FR 18960.
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Multiple comments submitted in response to the DOT Notification of
Regulatory Review addressed the $50,000 monetary damage threshold for
reporting gas pipeline incidents. The Associations, GPTC, and GPA
Midstream submitted comments recommending an increase in the monetary
damage threshold for reporting gas pipeline incidents. 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.\38\ 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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\38\ This analysis is based on the CPI for All Urban Consumers
(CPI-U) from the Bureau of Labor Statistics, accessible at https://data.bls.gov/cgi-bin/cpicalc.pl.
---------------------------------------------------------------------------
PHMSA proposed in the NPRM to raise the reporting threshold for
incidents that result in property damage to $122,000, consistent with
inflation since 1984. The property damage criterion will continue to
include losses to the operator and others but exclude the cost of lost
gas. PHMSA did not propose any changes to the other criteria in the
Sec. 191.3 definition of an incident. The NPRM stated that PHMSA
intended to base any finalized version of this provision on the price
level at the time of publication of a final rule. PHMSA also requested
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 de facto annually-
decreasing threshold after inflation would provide beneficial
information on contributing risk factors and incident trends.
The NPRM also stated that PHMSA intends to 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] TR11JA21.018
Where Tn is the revised damage threshold, Tp is the previous damage
threshold, CPIn is the average CPI-U for the preceding 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 (FRA) implemented to update the criteria for
reporting accidents/incidents at 49 CFR 225.19 and appendix B to part
225.\39\
---------------------------------------------------------------------------
\39\ 85 FR 79130 (Dec. 9, 2020) (updating FRA's monetary
threshold for railroad incident reporting requirements by way of
annual notices published on FRA's website).
---------------------------------------------------------------------------
2. Summary of Public Comments
Several commenters (including AGA et al., AmeriGas, the Arkansas
Independent Producers and Royalty Owners (AIPRO), GPA Midstream, NPGA,
Paiute, the GPTC and SPP) expressed support for PHMSA's proposal to
update the threshold for property damage in the definition of an
incident to account for inflation. AGA, API, APGA, GPA Midstream, and
INGAA reiterated their support for this proposal in supplemental
comments submitted after the GPAC meeting. AGA et al. also supported
revising the initial property damage threshold to reflect inflation at
the time of final rule publication. AGA et al. stated that the cost of
repairing or remediating incident damage in today's environment is far
greater than it was in 1984, and that even with the inflation
adjustment, more minor events will still be reported
[[Page 2220]]
as an incident than would have been in 1984. They asserted that this
results in a distorted view of pipeline safety performance, since
reportable incidents are often used as a performance metric for the
natural gas industry. AGA et al. also stated that the increase in the
reporting threshold will reduce the number of calls made to the
National Response Center (NRC) for minor events that are easily
remediated by the operator, and reduce the potential of having to
report minor incidents that unnecessarily tie up resources of both the
producer and PHMSA. FreedomWorks stated that adjusting the threshold
for inflation is simply good housekeeping, adding that it should have
been indexed to inflation when the threshold was originally
established. This commenter stated their support for including this
amendment in the proposed rule while noting that eventually eliminating
the property damage criterion entirely would be ideal. Paiute and
Southwest also supported the proposed change, noting that it would
directly reduce the regulatory burden on them. Southwest further stated
that they analyzed the details of the Sec. 191.3 reports their company
has made since 2010 where the only reporting criteria met was exceeding
the $50,000 estimated property damage threshold and determined that
only 9 percent of this subset of reported incidents would have met the
revised proposed estimated property damage threshold of $122,000.
TC Energy supported changing the incident definition to adjust the
amount of monetary damage to align with inflation, and recommended a
monetary damage threshold of $250,000, which they stated would
accurately reflect repair costs for minor incidents. They stated that
while the proposed threshold of $122,000 may take inflation into
account, it will continue to result in several minor incidents being
considered reportable due to the cost to respond based on labor, repair
materials, and permitting.
AGA et al. also supported updating the reporting threshold every 2
years to account for inflation, noting that periodic updates will
provide certainty and avoid a repeat of the current situation where the
current threshold does not account for over 3 decades of inflation. AGA
et al. further supported implementing the biennial periodic updates via
notice on the PHMSA website, stating that conducting biennial
rulemakings to update the threshold seems unnecessarily burdensome for
both PHMSA and stakeholders. They asserted that the current NPRM
provides adequate notice and opportunity for comment on the proposed
method to update the threshold periodically. They recommended that
PHMSA revise Sec. 191.3 to clarify in the final rule the agency's
intended process for periodically updating the threshold. FreedomWorks
recommended that PHMSA mandate a biennial update in the final rule.
NPGA agreed with periodic modifications to the threshold, suggesting
annual updates by means of a direct final rule published in the Federal
Register. TC Energy, on the other hand, commented that biennial updates
may prove burdensome, but supported incorporating whatever process
PHMSA settles on for periodically updating the property damage
threshold into the PSR.
NAPSR suggested that PHMSA use the language ``$50,000 or more as
measured in 1984 dollars adjusted for inflation,'' which would prevent
the need to amend the PSR every year. They further suggested that PHMSA
could announce the reporting threshold annually as is done with random
drug testing rates, and civil penalties as found in 49 CFR 190, or by
simply updating the incident report forms and instructions every year
to reflect the recalculated reporting threshold. However, NAPSR also
noted that the historical data collected by PHMSA using the prior
criteria may result in skewed statistical incident results until
several years of collection using the new formula, if adopted, is
completed. NAPSR suggested that PHMSA first study the effects of
changing the reportable criteria dollar amount and how they plan to
reconcile any new data to provide meaningful information to the State
programs and to the public. They also suggested that PHMSA consider how
such data will relate to any required cost benefit analysis related to
future pipeline safety regulations and whether any change to the dollar
reporting criteria could affect the ability to promulgate effective
regulations.
Two commenters opposed changing the monetary threshold for incident
reporting from $50,000 to $122,000. PST commented that PHMSA should be
seeking to obtain more information about pipeline failures, not less.
They asserted that PHMSA can only make regulatory decisions about
design, manufacture or operating conditions that they know cause
problems, and if they are told about fewer problems, they will not be
able to determine whether they need to regulate certain safety issues.
They further stated that if PHMSA is determined to re-define the term
``incident,'' it should undertake a comprehensive look at that
definition, and not merely adjust the property damage criteria. They
asserted that making incremental, sequential adjustments to the
definition will disrupt and frustrate trend analyses, recommending that
PHMSA identify, analyze, and consider all potential changes at once.
They stated that reducing the number of incidents reported provides
PHMSA less safety data, and saves operators very little money, while
potentially misleading the public about the improvement in the number
of reported incidents that occur in future years. PST further stated
that PHMSA and the industry have all committed to pursuing a goal of
zero incidents, and that PHMSA should not facilitate that goal by
defining reportable incidents away.
Theresa Pugh Consulting also opposed changing the monetary
threshold for incident reporting. They stated that since 1984, the
United States has become more densely populated such that natural gas
pipelines and compressor stations could cause ``partial damage to
$50,000 in property that merits reporting to PHMSA.'' While the
commenter recognized there is a regulatory cost associated with this
reporting, they asserted that it is the cost of doing business in a
critical, necessary and dangerous business. The commenter asserted that
property damage is still important if it is valued at greater than
$50,000, noting that a damaged or lost $50,000 structure or capital
equipment can be a major business investment even if it might seem less
significant to a multimillion-dollar pipeline project.
One commenter recommended that while PHMSA is addressing the
monetary damage limits in the definition of incident in Sec. 191.3, it
should also address the issue of how operators determine what
constitutes a ``significant event'' under item (iii) of the definition.
The commenter stated that the failure of an operator to evaluate their
system and define what is significant for their personnel leads to
confusion and can cause delayed reporting, or even non-reporting, of
incidents.
The GPAC voted 11-2 in favor of PHMSA's proposed amendment to the
definition of an incident provided that PHMSA adopted an updated
property damage criterion commensurate with the CPI at the time of
final rule publication. The GPAC further recommended regular
administrative updates using procedures like those proposed by the
Federal Railroad
[[Page 2221]]
Administration for part 225.\40\ Two members voted against the proposed
amendments.
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\40\ As noted earlier, FRA finalized that proposal in December
2020.
---------------------------------------------------------------------------
3. PHMSA Response
PHMSA agrees with comments supporting the adoption of an up-to-date
property damage threshold in the final rule. The most recent complete
calendar year is 2019. Therefore, the property damage criterion
following the effective date of this final rule is set to $122,000
consistent with CPI inflation between 1984 and 2019.
PHMSA also agrees that it is appropriate to perform updates in the
future to account for inflation via a pre-established formula. To this
end, PHMSA has incorporated the formula described in the preamble to
the NPRM into a new appendix A to part 191. In the future, annual
updates to the property damage criterion will be calculated based on
this formula and posted to PHMSA's website such that they will become
effective July 1 of each year. The revision to the incident definition
has no direct safety impact, better reflects the intent of the original
property damage criterion, and only impacts reports of releases without
significant safety or environmental consequences. Whether a release is
classified as an incident has no effect on an operator's regulatory
obligation to repair hazardous leaks promptly (Sec. 192.703) and
establish and follow procedures for responding to gas pipeline
emergencies (Sec. 192.615) and investigating failures (Sec. 192.617).
None of the repair criteria in part 192 depend on whether a leak or
defect results in a reportable incident.
PHMSA disagrees that changing the property damage criterion
adversely affects trend analysis. In fact, a static property damage
threshold decreases in real value time. PHMSA already addresses this
issue when performing and presenting trend analysis of ``significant''
incidents. PHMSA's analyses of ``serious incidents'' include only
incidents that result in reported deaths or injuries and are not
affected by inflation because the ``serious'' threshold criteria do not
include a property damage criterion. In contrast, PHMSA uses the term
``significant incidents'' to mean those with (1) reported deaths or
injuries, or (2) $50,000 or more in total costs, measured in 1984
dollars. Additional information on these trend analyses is available on
PHMSA's web pages for National Pipeline Performance Measures \41\ and
Pipeline Incidents, 20 Year Trends.\42\ PHMSA currently uses inflation
data published by the Bureau of Economic Analysis, the Government
Printing Office, and the Energy Information Administration in
calculating inflation adjustments for ``significant incidents.''
Following the effective date of the final rule, PHMSA will no longer
employ those tools in adjusting the ``significant incident'' property
damage threshold for inflation, but will instead use the Bureau of
Labor Statistics CPI.
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\41\ https://www.phmsa.dot.gov/data-and-statistics/pipeline/national-pipeline-performance-measures.
\42\ https://www.phmsa.dot.gov/data-and-statistics/pipeline/pipeline-incident-20-year-trends.
---------------------------------------------------------------------------
Regarding comments from Theresa Pugh Consulting, PHMSA did not
propose to create a new incident definition criterion for releases or
pressure drops that disrupt supply to downstream consumers and others
indirectly impacted by gas pipeline failures, therefore these
suggestions are outside the scope of the NPRM. PHMSA acknowledges that
property damage exceeding $50,000 can have a significant effect on
third parties affected by the release and notes that it understands
that some States have lower incident reporting thresholds to address
just that concern.
PHMSA disagrees with comments from TC Energy and FreedomWorks
suggesting more radical changes to the property damage criterion. PHMSA
does not believe that an arbitrarily higher damage threshold or
eliminating the reporting entirely would be appropriate. Even if repair
costs may have risen faster than inflation, TC Energy has not provided
a convincing rationale for why $250,000 represents current repair costs
for incidents across the industry. In addition, while a simple
inflation adjustment is consistent with how PHMSA currently uses
incident data, a significant change to the incident definition beyond a
simple inflation adjustment would affect the ability of PHMSA and other
data users to track incident trends as alluded to by other commenters.
PHMSA is deferring for a future rulemaking consideration of the
other amendments to the incident reporting criteria at Sec. 191.3 that
were suggested by comments received in the rulemaking docket. Further
evaluation of those proposals would be helpful.
Corrosion Control
Virtually all hazardous liquid and most natural gas transmission
pipelines in service today are made of steel. Metallic pipelines, when
not protected, react with the surrounding environment and can
deteriorate over time due to corrosion. Under certain conditions,
unprotected metal can corrode, causing gas leaks that can threaten
public safety. To guard against this, subpart I of part 192 of 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 proposed two amendments
related to corrosion control: first, to clarify that cathodic
protection rectifiers can be inspected remotely and second, to revise
the requirements for assessing atmospheric corrosion on distribution
service pipelines.
E. External Corrosion Control: Monitoring (Section 192.465)
1. PHMSA's Proposal
In the NPRM, PHMSA proposed to revise Sec. 192.465(b), ``External
corrosion control: Monitoring,'' to clarify that operators may monitor
rectifier stations remotely. Rectifiers are devices that direct an
electrical current on a pipeline to prevent external corrosion. Section
192.465(b) requires inspection of rectifiers on gas pipelines at
intervals not exceeding two and a half months, 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 proposed to
revise Sec. 192.465(b) to clarify that operators may inspect rectifier
stations directly onsite or by way of remote monitoring technologies.
The NPRM also clarified that, at a minimum, such an inspection consists
of recording amperage and voltage measurements. PHMSA also proposed to
require operators physically inspect rectifier stations that are being
monitored remotely whenever they conduct a cathodic protection test
pursuant to Sec. 192.465(a). For pipelines, other than separately
protected service lines or separately protected short sections of
transmission lines or mains,
[[Page 2222]]
Sec. 192.465(a) requires physical inspection once each calendar year.
2. Summary of Public Comments
Several commenters (including AGA et al. and TC Energy) supported
PHMSA's proposal allowing remote inspection of impressed current
cathodic protection sources. PST stated that they do not oppose
allowing the remote inspection of rectifier stations provided the
proposed addition of a requirement that remotely inspected rectifier
stations be physically inspected once a year is retained. AGA et al.
and TC Energy recommended that PHMSA clarify that operators must
physically inspect remotely inspected rectifiers at the cathodic
protection test frequency required in Sec. 192.465(a) and that the
rectifier inspection need not necessarily occur at the exact same time
as the cathodic protection testing. They indicated that the currently-
proposed wording of Sec. 192.465(b)(2) could be interpreted to require
a redundant physical inspection of the same rectifier every time each
of the pipeline segments influenced by that rectifier is tested, or
even multiple times per segment if the testing occurs over multiple
days. AGA et al. suggested specific revisions to the proposed Sec.
192.465(b)(2).
Four commenters (NPGA, AmeriGas, SPP, and a private citizen)
suggested changes to the proposed physical inspection interval. They
commented that if rectifier inspection can be done remotely and it is
performed at intervals no greater than two and a half months, PHMSA
should consider allowing an operator to extend the physical inspection
interval for rectifiers on distribution lines beyond once per year,
provided the results of remote inspections are properly documented. The
commenters claimed that documentation of the results will indicate if,
or when, physical inspection of the rectifiers is needed, but did not
provide a specific timeline.
One private citizen expressed opposition to the proposed amendment.
The commenter requested more frequent inspection of rectifiers, and
suggested that the proposed change does not align with industry
policies. The commenter noted that corrosion is one of the main causes
of pipeline failures and suggested that a physical inspection is
already required within the rectifier checks required in Sec.
192.465(b). Based on this interpretation of Sec. 192.465(b), the
commenter argued that PHMSA was effectively extending the required
interval to perform physical inspections of rectifiers and other
devices from six times a calendar year to once per calendar year.
The GPAC voted unanimously in favor of PHMSA's proposal with
respect to external corrosion monitoring provided that PHMSA clarify
that the physical inspection of a remotely inspected rectifier is
expected to occur annually rather than exactly when cathodic protection
surveys occur.
3. PHMSA Response
PHMSA has adopted the proposed amendments to Sec. 192.465 with
minor revisions to the physical inspection requirements. The amendments
clarify that remote inspection is permitted by the PSR. PHMSA's
corrosion enforcement guidance contains numerous interpretations
clarifying that Sec. 192.465(b) does not specify a particular
technology, but rather permits any technology that provides reliable
data, including ``electronic data collection and the subsequent
broadcast of this data to operators.'' \43\ PHMSA expects that the data
obtained from remote inspection of rectifiers will not adversely affect
the quality and quantity of information available on their function,
and does not expect the PSR amendments to Sec. 192.465(b) to have an
adverse impact on safety.
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\43\ See, e.g., PHMSA Pipeline Enforcement Guidance: Part 192
Corrosion Enforcement Guidance (2015), available at https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/Corrosion_Enforcement_Guidance_Part192_12_7_2015.pdf (citing PHMSA
Interpretation #PI-ZZ-080 (Aug. 19, 1991)).
---------------------------------------------------------------------------
PHMSA agrees with comments to specify that the physical inspection
should occur annually rather than exactly when a cathodic protection
survey is performed under Sec. 192.456(a). This change better reflects
PHMSA's intent for operators to perform an annual physical inspection.
This change has no impact on the intended frequency of inspections, but
provides more flexibility to operators and avoids situations where
inspections would have been required more frequently than intended.
PHMSA disagrees with the comment that Sec. 192.465(b) already
requires physical inspection during each rectifier inspection and that
PHMSA's proposal would lengthen the intervals for physical inspection.
While some operators may conduct a physical inspection with each of
their rectifier checks, Sec. 192.465(b) currently does not require
them to do so.
PHMSA does not adopt a longer physical inspection interval for
distribution pipelines as suggested in comments from LPG distribution
system operators and suppliers. These comments did not present an
alternative timeline that would have been appropriate for distribution
operators, and PHMSA believes that operators have ample opportunities
to perform an annual physical inspection during other inspection
activities.
F. Atmospheric Corrosion: Monitoring (Sections 192.481, 192.491,
192.1007, 192.1015)
1. PHMSA's Proposal
PHMSA proposed to revise Sec. 192.481 to establish a separate
atmospheric corrosion inspection interval for gas distribution service
pipelines. Currently, all onshore gas pipelines that are exposed to the
atmosphere must be inspected for atmospheric corrosion once every 3
years, with intervals not to exceed 39 months. This includes facilities
that are installed aboveground, in underground vaults, or inside
buildings. PHMSA proposed a maximum inspection interval for service
lines of once every 5 calendar years, with intervals not to exceed 63
months, unless atmospheric corrosion was identified on the last
inspection. If an operator identifies atmospheric corrosion on a
service line during an inspection, then the required interval for the
subsequent inspection would remain once every 3 years, with intervals
not to exceed 39 months. If no atmospheric corrosion is identified on a
subsequent inspection, then operators would be permitted to return to
using the 5-year inspection interval. PHMSA also proposed to revise
Sec. Sec. 192.1007(b) and 192.1015(b)(2) to clarify that consideration
of corrosion risks under DIMP explicitly includes atmospheric
corrosion. PHMSA did not propose any changes to the inspection
requirement for other facilities, including distribution mains. PHMSA's
proposed change was informed by its understanding that there has not
been a history of incidents caused by atmospheric corrosion on
distribution service lines since at least 1986 \44\ and therefore does
not anticipate a decrease in safety from these PSR revisions.
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\44\ 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.
---------------------------------------------------------------------------
2. Summary of Public Comments
Several commenters (including Oleksa and Associates, FreedomWorks,
and AGA et al.) expressed support for establishing a separate
atmospheric corrosion inspection interval for gas distribution service
pipelines. FreedomWorks stated that the changes would reduce the costs
for both
[[Page 2223]]
operators and inspectors. AGA et al. supported revising Sec. 192.481
to align the inspections intervals for atmospheric corrosion with those
of leak surveys required by Sec. 192.723. AGA et al. asserted that the
NPRM's proposed PSR revisions would reduce regulatory burdens while
enhancing pipeline safety in that the resources saved from such
alignment could be reallocated to other pipeline safety activities and
asset improvement projects.
Some commenters (including SPP, NPGA, and AmeriGas) supported the
extension of the inspection interval to 5 years for service lines, but
recommended that if documented action were taken to remediate the
coating as specified in Sec. 192.479, then the inspection interval
should remain at 5 years. The commenters stated that there is not a
need to drop down to 3 years if remediation occurs.
AGA et al. and GPTC agreed that the existing 3-year interval when
corrosion is identified is not necessary to manage atmospheric
corrosion risks if the service line is replaced or remediated,
especially considering existing DIMP requirements, and the proposed
requirement to consider atmospheric corrosion risks under DIMP included
in the NPRM. They agreed with PHMSA's assessment that there is
expectation for 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 Sec. 192.481. AGA et al.,
therefore, recommended a prescriptive remediation requirement in lieu
of a shortened inspection cycle. They stated that by remediating
through recoating or replacement, operators can continue to keep all
service pipelines on a 5-year inspection cycle. They provided specific
regulatory text revisions in their comment. AGA et al. also requested
that PHMSA remove the word ``evaluate'' from Sec. 192.481(a). They
noted that PHMSA did not provide justification for adding the
requirement to evaluate under Sec. 192.481(a). INGAA, AGA, APGA, API,
and GPA Midstream submitted supplemental comments after the GPAC
meeting arguing that the 3-year inspection interval when corrosion has
been identified would negate any cost savings from the proposed
revisions to Sec. 192.481.
Similarly, NAPSR commented that if atmospheric corrosion is found
that corrosion should be remediated rather than be subject to a shorter
inspection interval. NAPSR argued this would be more reliable from a
safety perspective than establishing a shorter inspection interval.
Alternatively, NAPSR recommended that PHMSA consider revising both
Sec. Sec. 192.481 and 192.723 to require a shorter, perhaps 3- or 4-
year, residential leak survey requirement and require that operators
complete their atmospheric corrosion survey at the same interval. NAPSR
argued this would provide for greater safety regarding leak surveys,
while making it more practical to combine compliance intervals for two
operation and maintenance categories. NAPSR further commented that any
change to the atmospheric corrosion control inspection interval should
be accompanied by a change to the record keeping requirements in Sec.
192.491. NAPSR recommended that operators be required to retain records
for the previous two inspection cycles.
A2LA recommended that PHMSA implement a risk-based approach to
determine permissible inspection intervals rather than the 3-year or 5-
year intervals described in the NPRM. A2LA stated the risk-based
approach can then account for considerations such as the age of the
pipeline, climate, geologic conditions, use, and maintenance history.
They agreed with the proposed rulemaking that the maximum inspection
interval for service lines should be 5 calendar years, with intervals
not to exceed 63 months.
Two gas distribution operators and an industry organization
commented that it is unclear whether, if corrosion was identified, a 3-
year inspection interval would be required for the entirety of the
distribution system or just at the location or address where the
corrosion exists. They recommended that PHMSA consider clarifying that
the 3-year inspection interval applies to ``only such areas as
corrosion was identified.''
PST commented that they are unable to support changes in monitoring
frequency because corrosion continues to cause many incidents. They
commented that corrosion-related incidents indicate that more
prescriptive corrosion monitoring regulations might be warranted.
However, they noted that they do not strongly oppose this change, as
PHMSA indicates it has no recent records of incidents caused by
atmospheric corrosion on distribution service lines.
The GPAC voted twice on this amendment. First, the GPAC voted 7-5
in favor of the proposed rule with respect to atmospheric corrosion,
provided that PHMSA amend Sec. 192.491(c) to clarify that an operator
must retain records of the last two atmospheric corrosion inspections
to use the 5-year inspection interval. This vote recommended retaining
the proposed requirement to inspect lines where corrosion was
identified on the last inspection within 3-years, and did not
incorporate the remediation alternative to a 3-year inspection that was
suggested by some commenters.
Second, the GPAC voted 10-2 in favor of the proposed rule with
respect to atmospheric corrosion if PHMSA adopted a 5-year cycle rather
than a 3-year cycle when atmospheric corrosion is found, provided that
the operator has evaluated and remediated the facility and there is no
evidence of systemic atmospheric corrosion due to the environment or
similar factors.
3. PHMSA Response
After considering the public comments and the GPAC recommendations,
the final rule adopts the amendment with respect to atmospheric
corrosion inspection of service lines as proposed with minor
clarification to recordkeeping requirements in Sec. 192.491(c).
Alignment of atmospheric corrosion inspection intervals with those for
leakage surveys in Sec. 192.723 will allow greater scheduling
flexibility for operators and decreased costs arising from less
frequent atmospheric inspections. As stated in the NPRM, PHSMA is
unaware of any pipeline incidents arising from atmospheric corrosion on
a service line. In addition, 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.\45\
PHMSA has not observed an increase in leaks or incidents from this and
other State waivers. For these reasons, PHMSA finds that a longer
atmospheric corrosion inspection interval is supported in areas with
low observed atmospheric corrosion risk.
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\45\ Additional information on these historical examples is
available in the rulemaking docket and the docket for the South
Dakota State waiver (PHMSA-2019-0052).
---------------------------------------------------------------------------
The final rule applies the new 5-year inspection interval to
distribution service lines. Although PHMSA acknowledges that operators
have reported atmospheric corrosion incidents on distribution mains,
PHMSA understands the design and operational characteristics of service
lines make them less susceptible to atmospheric corrosion induced
failure. Compared to distribution mains, service lines tend to have
smaller diameters,
[[Page 2224]]
have lower flow rates, and are constructed with thicker walls relative
to the outside diameter of the pipeline. They can therefore endure more
atmospheric corrosion induced metal loss before operating stresses
would compromise pipeline integrity. In addition, aboveground
distribution facilities other than service lines (i.e. mains) must be
inspected more frequently under part 192, providing ample opportunity
for operators 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 is necessary to ensure that distribution facilities
are adequately inspected for atmospheric corrosion sufficiently
frequently so that it can be remediated before it leads to a failure.
An open-ended reference to DIMP, as suggested in the Associations'
comment on the DOT Notification of Regulatory Reform, would not provide
this safeguard. The proposed maximum interval of 5 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 under Sec. 192.723(b)(2) concurrently.
PHMSA was not persuaded that there is significant benefit to allowing
atmospheric corrosion inspection intervals longer than the maximum
leakage survey interval as described by some commenters. Inspecting the
aboveground portion of a service line is not a significant additional
burden when operators are already walking the service line to perform
leakage surveys.
The proposed revisions to Sec. Sec. 192.1007(b) and 192.1015(b)(2)
to evaluate atmospheric corrosion risks under DIMP and the shorter
inspection interval for pipelines with observed corrosion will also
ensure that operators of service pipelines with atmospheric corrosion
threats take appropriate action to maintain the integrity of those
pipelines.
Those revisions clarify that consideration of corrosion under DIMP
must include 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 to take mitigative action, such as more frequent inspection or
maintenance activities, as part of their DIMPs and accurately and
completely document such actions.
The final rule does not adopt proposals (by commenters and GPAC)
for remediation as an alternative to the NPRM's approach of shorter
inspection intervals following observation of atmospheric corrosion.
While commenters suggested a ``prescriptive'' remediation requirement,
the regulatory language suggested in comments from the Associations
neither defines what constitutes an adequate repair of atmospheric
corrosion (other than replacement), nor how their proposal differs from
existing part 192 requirements for remediation and repair of
atmospheric corrosion and other conditions that could reduce the
pipeline's integrity. Based on the GPAC discussion, remediation as
discussed by commenters consists of removing corrosion with a wire
brush and repainting the facility pursuant to the existing Sec.
192.479 requirements. These actions are already required by existing
Sec. 192.481, through reference to Sec. 192.479, which requires an
operator to clean and suitably coat pipelines exposed to the
atmosphere, and Sec. 192.703 requires operators to replace, repair, or
remove pipeline segments that become unsafe and promptly repair all
hazardous leaks. In addition, finding atmospheric corrosion is an
indication that a corrosive environment may exist. Inspection of such
service lines within 3 years protects against this risk. Any
remediation alternative requires careful consideration of what
constitutes adequate remediation because corrosion has already been
identified on the pipeline.
PHMSA also declines to NAPSR's alternative approach of aligning
atmospheric corrosion inspection and leaky survey frequencies by
revising Sec. 192.723 to require more frequent leak surveys. PHMSA is
unaware of record evidence supporting a need for shortened leak survey
intervals, even as PHMSA finds that the absence of incidents resulting
from atmospheric corrosion support extending the inspection interval as
provided by this final rule. In addition, more frequent leak inspection
surveys under Sec. 192.723 will likely entail significant operator
costs without record evidence of a corresponding safety benefit.
PHMSA is not persuaded by arguments raised by GPAC members and
comments submitted after the GPAC meeting that reverting to a 3-year
inspection interval for a distribution service line after atmospheric
corrosion has been observed makes the amendment technically
impracticable or economically infeasible. A 3-year inspection interval
is the current requirement that has been in place for decades. Based on
cost estimates provided by industry comments, PHMSA determined in the
RIA that significant cost savings for the NPRM's proposed revisions to
atmospheric corrosion monitoring requirements stem from reduced
inspection frequency in the absence of observed atmospheric corrosion.
If, however, the operator observes atmospheric corrosion and remediates
it as required in part 192, then an operator should rarely observe
atmospheric corrosion during the 3-year inspection following
remediation, after which they may return to a 5-year inspection
interval and continue to enjoy cost savings into the future. An
operator can easily keep atmospheric corrosion and leakage surveys in
sync by performing the next leakage survey within 3 years and then
continuing every 5 years on subsequent inspections provided no
corrosion is identified in the future. If the operator is unable to use
the 5-year inspection interval effectively because they repeatedly
observe atmospheric corrosion, then the rule is working as intended to
protect the public in areas with high rates of atmospheric corrosion.
Finally, consistent with the recommendations of the GPAC and
comments received in the rulemaking docket, the final rule revises the
corrosion control recordkeeping requirements in Sec. 192.491(c) to
clarify that an operator must retain records of the two most recent
atmospheric corrosion inspections in order to use the 5-year inspection
interval for facility distribution service line. This change ensures
that operators can provide adequate documentation that corrosion was
not identified on a service line that is being inspected on a 5-year
interval.
ASTM and ASME Standards Incorporated by Reference
G. Plastic Pipe (Sections 192.7, 192.121, 192.281, 192.285, Appendix B
to Part 192)
1. PHMSA's Proposal
The NPRM proposed to update Sec. Sec. 192.7, 192.121 and appendix
B to part 192 to incorporate by reference the
[[Page 2225]]
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).\46\ ASTM D2513 specifies the design requirements of
Polyethylene (PE) pipe and fittings. These improvements include more
specific testing requirements for measuring resistance to ultraviolet
exposure and clarifying the applicability of the document to all PE
fuel gas piping. Consistent with the updated ASTM standard, PHMSA also
proposed to raise the diameter limit for using a design factor of 0.4
on PE pipe from 12 inches to 24 inches and add corresponding entries
for those sizes to the PE minimum wall thickness table at Sec.
192.121(c)(2)(iv). PPI, representing manufacturers of plastic pipe and
components, and a citizen commenter submitted comments in response to
the DOT Notification of Regulatory Review addressing this issue. PHMSA
reviewed ASTM D2513-18a 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. PHMSA also determined that the other
safety improvements since the 2012ae1 edition merit incorporation by
reference in the PSR as their incorporation would not have an adverse
impact on safety, while improving regulatory clarity and alignment with
consensus industry practices.
---------------------------------------------------------------------------
\46\ ASTM International, ASTM D2513-18a--``Standard
Specification for Polyethylene (PE) Gas Pressure Pipe, Tubing, and
Fittings'' (Aug. 1, 2018).
---------------------------------------------------------------------------
Currently, PHMSA incorporates by reference ASTM D2513-12ae1 into
item I, appendix B to part 192. While Table 2 (Outside Diameters and
Tolerances for Plastic Pipe) of ASTM D2513-12ae1 includes outside
diameter specifications for pipe sizes up to 24-inch nominal diameter,
Table 4 (Wall Thicknesses and Tolerances for Plastic Pipe) only
includes wall thickness specifications for pipe sizes up to 12-inch
nominal diameter. Because ASTM D2513 is the listed specification for PE
plastic pipe in appendix B to part 192, and Sec. 192.121(c)(2)(iv)
mirrored the published wall thicknesses and tolerances in Table 4 of
ASTM D2513-12ae, part 192 does not currently allow use of a 0.4 design
factor for PE pipe diameters above 12 inches. Now that the ASTM D2513-
18a includes in its Table 4 wall thicknesses for diameters through 24
inches, the corresponding table in Sec. 192.121(c)(2)(iv) can be
updated as well.
In the NPRM, PHMSA also proposed to modify requirements for joining
procedures in Sec. Sec. 192.281 and 192.285 to allow operators
additional flexibility when developing such procedures and to improve
safety. Specifically, PHMSA proposed to incorporate by reference the
2019 edition of ASTM F2620, ``Standard Practice for Heat Fusion Joining
of Polyethylene Pipe and Fittings'' and revise 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 \47\ in response to
the final rule entitled ``Pipeline Safety: Plastic Pipe Rule'' issued
on November 20, 2018.\48\
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\47\ Docket Number PHMSA-2019-0200. https://www.regulations.gov/docket?D=PHMSA-2019-0200.
\48\ 83 FR 58694.
---------------------------------------------------------------------------
In the Plastic Pipe Rule, PHMSA amended Sec. Sec. 192.281 and
192.285 to require that 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
contains 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 Sec. Sec. 192.281 and 192.285 could be
interpreted to require operators to requalify safe procedures that had
been qualified in the past in accordance with Sec. 192.283. AGA
commented that many operators use heat fusion procedures published by
PPI, such as PPI TR-33 and PPI TR-41. While PHMSA noted in the preamble
of the Plastic Pipe Rule that PHMSA would find a joining method
acceptable if ``an operator can demonstrate the differences are sound
and provide equivalent or better safety compared to ASTM F2620,'' AGA
raised concerns that the regulatory text itself does not necessarily
provide this flexibility, and suggested PHMSA explicitly allow the use
of other qualified procedures, such as PPI TR-33 and PPI TR-41.
In the NPRM, PHMSA proposed to revise Sec. Sec. 192.281 and
192.285 to achieve the flexibility sought in the Plastic Pipe Rule.
Specifically, PHMSA proposed 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 the internal and
external loads, and have 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 Rule, for
operators to demonstrate compliance, PHMSA expects operators to
document the differences from ASTM F2620 and demonstrate how the
alternate procedures provide an equivalent or superior level of safety.
Similarly, PHMSA proposed 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. If the operator's procedures are found
to be lacking in any way--such as changes to surface preparation,
heating temperatures, fusion pressures, cooling times that lack a
technical justification demonstrating an equivalent or superior level
of safety--they would be unacceptable and would not comply with the
PSR.
PHMSA also proposed to incorporate by reference the 2019 edition of
ASTM F2620. The updated edition of the standard clarifies the
relationship between ASTM F2620 and the certain PPI documents
referenced in AGA's petition within a new Note 1 in section 1.2. That
Note identifies parameters and procedures in F2620 that were developed
and validated using PPI TR-33 (butt fusion) PPI TR-41 (saddle fusion),
thereby facilitating operators' ability to referencing those PPI
documents in developing their technical justification for use of an
alternative procedures under Sec. 192.285(b)(2)(i). In addition, the
2019 edition of ASTM F2620 includes several incremental improvements on
the 2012 edition to safety and editorial clarity. These improvements
include a new section 6.4 that requires additional precautions
[[Page 2226]]
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. Further, 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 are
expected to reduce potential issues caused by inadequate surface
preparation, which has been a factor in past incidents.\49\
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\49\ National Transportation Safety Board, ``Safety Through
Reliable Fusion Joints,'' SA-047 (June 2015), https://www.ntsb.gov/safety/safety-alerts/Documents/SA_047.pdf.
---------------------------------------------------------------------------
PHMSA also proposed to clarify Sec. 192.285 in response to
questions PHMSA has received following publication of the Plastic Pipe
Rule. First, PHMSA proposed to remove references to testing in relation
to ASTM F2620 to clarify that only visual inspection in accordance with
that standard is required. Several stakeholders 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. Clarifying that operators must visually inspect
specimen joints in accordance with ASTM F2620 avoids confusion about
whether non-mandatory testing described in ASTM F2620 is required by
Sec. 192.285(b)(2)(i). PHMSA also proposed to clarify that testing in
accordance with Sec. 192.283(a) is still required for PE heat fusion
joints. The current text could be read to require only visual
inspection in accordance with ASTM F2620 for PE heat fusion joints. The
changes in this rule 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. Additional testing in accordance with the
appendix of ASTM F2620 is optional.
In addition to the matters raised above, PHMSA proposed correcting
amendments to address the following:
Design Pressure for Plastic Pipe
In Sec. 192.121(a), PHMSA proposed the words ``design formula'' be
replaced with the words ``design pressure,'' which is more accurate.
Minimum Wall Thickness for 1'' CTS Pipe
In the minimum wall thickness tables for PE (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)) pipe, PHMSA proposed that
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, most closely corresponds
to SDR 11, 1'' CTS pipe in the standards incorporated by reference for
the design of PE (ASTM D2513), PA-11 (ASTM F2945),\50\ and PA-12 (ASTM
F2785) \51\ plastic pipe and fittings.
---------------------------------------------------------------------------
\50\ ASTM F2945-12a ``Standard Specification for Polyamide 11
Gas Pressure Pipe, Tubing, and Fittings'' (Nov. 27, 2012).
\51\ ASTM F2785-12, ``Standard Specification for Polyamide 12
Gas Pressure Pipe, Tubing, and Fittings'' (Aug. 1, 2012).
---------------------------------------------------------------------------
Qualifying Joining Procedures
In Sec. 192.283(a)(3), ``no more than 25% elongation'' is
corrected to read ``no less than 25% elongation.'' PHMSA proposed to
clarify that the test required by this section is a tensile test.
Tensile testing is a measure of a material's resistance to pulling
forces. The revisions to Sec. 192.283(a)(3) made in the Plastic Pipe
Rule inadvertently removed the word ``tensile,'' though tensile
strength was still alluded to implicitly because elongation is a
measure of tensile strength. Reinserting the word tensile clarifies
this relationship.
Dates
In Sec. 192.121(c)(2) and (e), PHMSA proposed to clarify that PE
pipe and PA-12 pipe respectively produced on or after January 22, 2019
may use a DF of 0.40 rather than 0.32, subject to applicable
restrictions in those paragraphs.
Corrections to 192.7
PHMSA proposed editorial amendments to Sec. 192.7(a) to meet
incorporation by reference requirements of the Office of the Federal
Register and a revision to update the address for API.
2. Summary of Public Comments
ASTM D2513 and PE Pipe Diameter
Several commenters provided their support, with no additional
comments, for the proposed amendments in the NPRM.
AIPRO submitted comments supporting the incorporation by reference
of the 2018a edition of ASTM D2513 and conforming revisions to Sec.
192.121. Similarly, PPI stated their support to increase the allowable
dimensions for PE pipe using a 0.40 design factor up through 24 inches
along with the corresponding minimum wall thicknesses in Table 1 to
paragraph Sec. 192.121(c)(2)(iv). PPI stated that the revisions are
consistent with dimensions provided in ASTM D2513-18a and enables the
increased use of larger diameter PE in gas distribution, transmission,
and gathering systems.
PPI provided suggested regulatory text revisions for Sec.
192.121(a) to permit an operator to allow an operator to operate a
plastic pipe at a temperature up to 180 [deg]F, provided that the
hydrostatic design basis (HDB) is established at that temperature. PPI
noted that a survey of AGA members indicated that local distribution
companies desire to use plastic pipe at higher operating temperatures
providing them with more application options, and that use of these
higher performance plastic materials results in increased long-term
performance of the piping system and a safer gas system.
GPA Midstream supported incorporating by reference updated editions
of standards and believes that the latest editions should be adopted
wherever possible. GPA Midstream stated that relying on obsolete or
outdated editions of IBR standards creates unnecessary compliance
burdens, discourages innovation, and adversely affects the standards
development process. GPA Midstream noted that a significant number of
the IBR standards have undergone multiple revisions without being
updated to a newer or more recent edition. GPA Midstream requested that
PHMSA place a renewed emphasis on the timeliness of the incorporation
by reference process, particularly in cases where a prior edition of a
standard is already incorporated by reference. In such cases, PHMSA
should commit to adopting the latest edition of the standard or
providing an explanation for not doing so within 1 year of publication.
ASTM F2620 and Joining Requirements
AGA et al. supported the changes proposed to Sec. Sec. 192.281 and
192.285. They commented that the proposed revisions in the NPRM aligned
with AGA's petition for reconsideration of the Plastic Pipe Rule, and
allow operators to use alternate procedures to join PE which are
equivalent or more stringent than the heat fusion procedure detailed in
the 2012 edition of ASTM F2620.
PPI supported PHMSA's proposed revision to Sec. Sec. 192.281(c)
and 192.285 providing for alternative written heat fusion procedures
that provide an equivalent or superior level of safety.
[[Page 2227]]
PPI also suggested incorporating PPI-TR-33, ``Generic Butt Fusion
Joining Procedure for Field Joining Polyethylene Pipe'' and TR-41,
``Generic Saddle Fusion Joining Procedure for Polyethylene Gas Piping''
into Sec. 192.281(c) in addition to ASTM F2620. PPI explained that
these additions would help clarify the language and account for proven
procedures that have been successfully used in industry for many years.
A2LA suggested that PHMSA also incorporate by reference ISO/IEC 17025,
``General Requirements for the Competence of Testing and Calibration
Laboratories'' and require alternative written procedures be validated
by laboratories certified in accordance with that document. A2LA
commented that ISO/IEC 17025 recommends that a testing laboratory uses
consensus methods and has procedures for the selection of methods, and
verify that a testing laboratory can properly perform methods by
ensuring that it can achieve the required performance and maintain
records of the verification. Regarding PHMSA expecting operators to
document the differences from ASTM F2620 and demonstrate how the
alternate procedures provide an equivalent or superior level of safety,
A2LA recommended that the organizations conducting the inspections and
testing be accredited, in accordance with the relevant ISO/IEC
standards include requirements for impartiality.
Southwest Gas Corporation (Southwest) raised concerns with the
addition of the language ``or superior'' in the proposed language of
both Sec. Sec. 192.281 and 192.285. Southwest believes that this
language ``or superior'' implies an increased performance standard not
defined in either ASTM F2620 or part 192. Southwest requested that
PHMSA consider removing the language ``or superior'' from the proposed
revisions to both Sec. 192.281(c) and Sec. 192.285(b)(2)(i) and
provided its preferred regulatory text.
1-Inch CTS Pipe
The Associations and NAPSR commented that operators commonly use 1-
inch CTS pipe with a wall thickness of 0.099 inches, rather than 0.101
inches in the proposed rule. Both wall thickness specifications are
listed as options in Table 3 of ASTM D2513. NAPSR requested
clarification of whether operators are required to use a design factor
of 0.32 for PE pipe with a minimum wall thickness of 0.099-inch, and if
thicker pipe is required to use a 0.40 design factor. The Associations
raised concerns about the impact to operators and manufacturers who
have an inventory of 0.099-inch wall thickness PE pipe and suggested
that PHMSA correct the proposed amendments to the minimum wall
thickness table at Sec. 192.121(c)(2)(iv) to reference 0.099-inch
thick, 1-inch CTS pipe that is commonly in use.
Qualifying Joining Procedures
PPI supported correcting Sec. 192.283(a)(3), and allowing visual
inspection in accordance with established written procedures in Sec.
192.285(b)(2)(i).
GPAC Recommendation
The GPAC voted unanimously in favor of PHMSA's proposed amendment
with respect to plastic pipe requirements, provided PHMSA correct the
minimum wall thickness tables to specify a 0.099-inch wall thickness
for 1-inch CTS plastic pipe as recommended in the written comments from
the Associations and NAPSR.
3. PHMSA Response
Based on the comments, the final rule adopts the plastic pipe
amendments as proposed except for a change to the minimum wall
thickness required to use plastic pipe with a size of 1-inch CTS with a
design factor of 0.40 rather than 0.32. The final rule incorporates the
0.099-inch minimum wall thickness for 1-inch CTS plastic pipe.
PHMSA expects that the incorporation of updated industry standards
pertaining to plastic pipe design will not adversely affect safety. The
updated standards incorporated by reference in this final rule reflect
the benefit of testing, lessons learned, and operational best practices
from the increasingly widespread use of plastic pipe in gas
transmission, distribution and gathering applications. Significantly,
those updated industry standards reflect a greater comfort within
industry regarding the safety of the use in those applications of
larger-diameter plastic piping when subject to rigorous design
standards. Based on its review of those standards and the
administrative record in this rulemaking, PHMSA is similarly satisfied
that their incorporation within the PSR will not have a detrimental
impact on safety. PHMSA has provided a discussion of the changes in the
updated editions of ASTM D2513 and ASTM F2620 in the summary of the
proposed changes in section III.G.1 above.
ASTM D2513 and PE Pipe Diameter
The final rule incorporates by reference the 2018a edition of ASTM
D2513 and allows the use of a 0.40 design factor for PE pipe produced
on or after the effective date of the rule with a maximum diameter of
24 inches as proposed in the NPRM. PHMSA proposed no changes to the
design pressure formula for PE pipe at Sec. 192.121(c)(2), and
therefore declines to adopt the design factor change for PE piping
suggested by PPI without the benefit of further technical evaluation
and public comment. Similarly, PHMSA may consider allowing an operator
to more directly establish a HDB rating at 180 [deg]F within the design
pressure formula at Sec. 192.121(a) in a future rulemaking after
further review of the safety effects of such a change. PHMSA notes that
Sec. 192.121(a) allows an operator to interpolate the design pressure
down from 180 [deg]F, meaning they could use a pipe with an HDB rating
at 180 [deg]F but have to use a formula to determine the design
pressure at a lower temperature listed in Sec. 192.121(a). PHMSA
cautions users that not all PE compounds are rated at 180 [deg]F.
Regarding the GPA Midstream comment concerning other documents that
are currently incorporated into part 192, PHMSA periodically issues
rules updating the standards that are incorporated by reference,
provided the 2018 edition of ASTM D2513 has been evaluated and its
incorporation determined consistent with PHMSA's safety mission. More
recent versions of this and other standards incorporated by reference,
including those related to plastic pipe and components, that were not
included in the NPRM may be considered for updates in other rulemaking
proceedings.
ASTM F2620 and Joining Requirements
The final rule also adopts the clarifications to joining
requirements as proposed with minor editorial revisions. PHMSA did not
propose in the NPRM to incorporate by reference PPI TR-33, PPI TR-41,
or ISO/IEC 17025, and therefore declines to incorporate them by
reference without the benefit of additional public comment and
technical evaluation. However, PHMSA understands that many of the
procedures in TR-33 and TR-41 are similar or identical to the
procedures specified in the 2019 edition of ASTM F2620. There are,
however, still some differences such as heating temperatures. If an
operator can demonstrate that their alternative procedure based on
those documents provides an equivalent or superior level of safety
compared with ASTM F2620, it would be acceptable under the amendments
adopted in this final rule.
[[Page 2228]]
PHMSA disagrees with comments that including the phrase ``or
superior'' imposes new requirements or adds uncertainty to the changes
in Sec. Sec. 192.281 and 192.285. An operator need only demonstrate
that their alternative procedure provides an equivalent level of
safety; the addition of the term ``or superior'' exists to ensure that
a procedure with requirements that may be more conservative than ASTM
F2620 is also acceptable. PHMSA has revised the regulatory language at
Sec. 192.281 proposed in the NPRM to clarify that the operator need
only demonstrate that the alternative procedure provides an equivalent
or superior level of safety rather than demonstrate the alternative
procedure is itself superior.
1-Inch CTS Pipe
PHMSA agrees with commenters that 0.099 is an acceptable minimum
wall thickness specification. While 0.101 inches more closely
corresponds to SDR 11, both 0.099-inch and 0.101-inch wall thickness
for 1-inch CTS pipe are technically SDR 11 specifications. In addition,
the two specifications are within allowable tolerances of each other in
the ASTM codes. Therefore, PHMSA does not have a safety concern with
using a 0.40 design factor with 0.099-inch wall thickness for 1-inch
CTS plastic pipe and recognizes that it is in common use.
H. Test Requirements for Pressure Vessels (Section 192.153)
1. PHMSA's Proposal
Section 192.153 defines design requirements for prefabricated units
and pressure vessels (hereafter referred to as pressure vessels)
fabricated by welding. In particular, Sec. 192.153(a) requires that
operators establish the design pressure of components fabricated by
welding whose strength cannot be determined to establish the design
pressure of those components in accordance with section VIII, division
1 of the 2007 edition of the American Society of Mechanical Engineers
(ASME) Boiler and Pressure Vessel Code (BPVC) which is incorporated by
reference in Sec. 192.7.\52\ Section 192.153(b) requires operators to
design, construct, and test prefabricated units that use plate and
longitudinal seams in accordance with either ASME BPVC section I,
section VIII, division 1, or section VIII, division 2. In addition,
Sec. 192.505(b) requires operators to pressure test compressor
station, regulator station, and measuring stations to Class 3 location
test requirements; for pipelines installed after November 11, 1970,
this represents a required test factor of at least 1.5 times the
maximum allowable operating pressure (MAOP).\53\
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\52\ ASME Boiler & Pressure Vessel Code, 2007 edition (July 1,
2007).
\53\ Section 192.619(a)(2) requires a test pressure of at least
1.5 times the MAOP in a Class 3 or Class 4 location for pipelines
installed after November 11, 1970.
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On March 11, 2015, PHMSA published a final rule titled, ``Pipeline
Safety: Miscellaneous Changes to Pipeline Safety Regulations.'' \54\
The final rule created a new Sec. 192.153(e), which clarified that
pressure vessels subject to Sec. 192.505(b) must be pressure tested to
at least 1.5 times the MAOP of the pipeline. INGAA subsequently
submitted a petition for reconsideration of the Miscellaneous Rule
concerning the revision to Sec. 192.153.\55\ The petitioner argued
that PHMSA lacked technical justification for a 1.5 times MAOP test
factor versus the 1.3 times the Maximum Allowable Working Pressure
(MAWP) \56\ test factor permitted in the ASME BPVC since the 2001
edition and all subsequent editions of the standard. PHMSA had
incorporated by reference the 2001 edition of the ASME BPVC into part
192 effective July 14, 2004, and the divergence between the required
test factor in Sec. 192.505(b) and section VIII, division 1 of ASME
BPVC persisted until the Miscellaneous Rule became effective in
2015.\57\
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\54\ 80 FR 12762 (Miscellaneous Rule).
\55\ Docket No. PHMSA-2018-0046-0055.
\56\ MAWP is the design pressure in the ASME BPVC. The test
factors in the ASME BPVC refer to the MAWP and are used to
substantiate the design pressure of the vessel. Because the design
pressure of a pressure vessel (the MAWP) must be equal to or greater
than the MAOP of the pipeline, the PSR uses the more demanding MAOP
metric.
\57\ PHMSA, ``Pipeline Safety: Periodic Updates to Pipeline
Safety Regulations,'' 80 FR 12762 (June 14, 2004).
---------------------------------------------------------------------------
PHMSA, meanwhile, had commissioned a report by the Oak Ridge
National Laboratory (ORNL) on the safety equivalence between the 1992
edition and the 2015 edition of the ASME BPVC. PHMSA understands that
most pressure vessels in pipeline service are designed to ASME section
VIII, division 1. For hydrostatic pressure tests, the 1992 edition of
section VIII division 1 of the ASME BPVC provides for a hydrostatic
pressure test factor of 1.5 times MAWP, while the 2001 and all
subsequent editions provide for a hydrostatic pressure test factor of
1.3 times MAWP. The ORNL report found that these different editions of
ASME BPVC section VIII, division 1 maintain safety through the design
and fabrication of pressure vessels and hydrostatic pressure test,
notwithstanding the difference in their hydrostatic pressure test
factors of 1.3 and 1.5. A copy of this report is available in the
docket.
In the NPRM, PHMSA proposed to revise the test requirements for the
pressure vessels described in Sec. 192.153. First, PHMSA proposed to
revise Sec. 192.153(e) to require a pressure test factor of at least
1.3 times the MAOP for all pressure vessels installed since July 14,
2004, provided the component has been tested in accordance with the
ASME BPVC, as required by existing Sec. 192.153(b). Consistent with
this change and the requirements in the ASME BPVC, PHMSA also proposed
to exempt vessels installed after July 14, 2004 from the strength
testing requirement at Sec. Sec. 192.505(b) and 192.619(a)(2), which
require a test factor of 1.5 times the MAOP. The test requirements for
any pressure vessel with an MAOP established under the alternative MAOP
requirements at Sec. 192.620 would remain unchanged.
Second, PHMSA proposed a new Sec. 192.153(e)(2) that would exempt
pressure vessels installed after July 14, 2004 but before the effective
date of the final rule from testing duration requirements at Sec. Sec.
192.505(c), (d) and 192.507. In contrast, pressure vessels installed on
or after the effective date of the final rule would be subject to the
long-standing pressure test duration requirements in subpart J.
Third, PHMSA proposed Sec. 192.153(e)(3)(ii) to accept, subject to
certain conditions, a pre-installation pressure test by the component
manufacturer for pressure vessels installed after the effective date of
the final rule but which have not previously been used in service.
PHMSA proposed to accept those manufacturer pressure tests for the
purposes of meeting the pressure testing and MAOP requirements in part
192 provided the operator conducts and documents an inspection
certifying that the pressure vessel has not been damaged during
transport and installation into the pipeline. If the inspection reveals
that the pressure vessel has been damaged, the component would have to
be remediated consistent with the ASME BPVC and part 192. A pressure
vessel used prior to installation on a pipeline facility would have to
be pressure tested again, consistent with the existing requirement at
Sec. 192.503(a).
2. Summary of Public Comments
AGA et al. generally supported the PSR amendments proposed in the
NPRM but suggested substantive revisions to the requirements for
accepting a manufacturer's test of a pressure vessel. AGA et al.
emphasized that the NPRM's integration of ASME
[[Page 2229]]
BPVC requirements within its proposed PSR revisions leverages an
internationally recognized standard of safety applied by several
Federal regulators in their oversight activities. AGA et al. agreed
with the NPRM's approach of allowing operators to rely on a
manufacturer's pressure test accompanied by a visual inspection for
newly-manufactured vessels, but requested PHMSA extend this
authorization to relocations of existing components as well.
AGA et al. noted that retesting ASME pressure vessels is not
required by the ASME BPVC--but if an operator voluntarily undertook
retesting, the ASME BPVC would require oversight by an authorized
inspector. They concluded that retesting is therefore unnecessary and
can lead to costs and operational disruptions because most operators do
not have an authorized inspector on staff to oversee that retesting.
They further commented that PHMSA should not require pressure vessels
be pressure tested or inspected after installation or in situ, because
in many cases it may be impracticable or unsafe to do so, especially
for pressure vessels used in compressor stations. Finally, AGA et al.
submitted comments opposing the NPRM's proposed requirement that
pressure vessels that have been used prior to being installed or
relocated must be retested in place in accordance with Subpart J. They
commented that retesting relocated vessels is not required by the ASME
BPVC, and that inspection rather than pressure testing is the
appropriate method to confirm the integrity of previously-used,
relocated pressure vessels.
PST opposed the proposed revisions to Sec. 192.153, contending
that PHMSA lacked sufficient technical justification for the proposed
changes. PST argued that the ORNL report does not support PHMSA's
conclusion that safety would not be adversely affected by NPRM's
proposed reduction of the pressure test factor at Sec. 192.153(e). PST
asserted that the ORNL report did not conclude that components designed
and fabricated under the 2015 edition of the ASME BPVC standards and
tested to its lower (1.3 times MAWP) hydrostatic pressure test factor
were necessarily as safe as those designed and fabricated to the higher
hydrostatic pressure test factor (1.5 times MAWP) in the current text
of Sec. Sec. 192.153(e) and 192.505(b) (which were based on the test
factors from the 1998 and prior editions of the ASME BPVC). Rather, PST
characterizes the hydrostatic pressure test factor as only ``one of
[several] changes between [the] two editions'' (1992 and 2015) compared
by the ORNL report that would need to be evaluated to determine the
safety impact of the NPRM's revisions to Sec. 192.153 compared to the
current PSR. PST also noted that the NPRM proposed applying the lower
test factor in the 2015 ASME BPVC not only to components installed
since the 2015 edition, but also components installed over the previous
decade. Lastly, PST alleged that the NPRM's proposed reduction in the
test factor at Sec. 192.153(e) violates the prohibition in 49 U.S.C.
60104(b) on retroactive application of design standards insofar as it
purports to impose new design, installation, construction, and testing
standards on previously-installed components. PST representatives
reiterated their concerns in a conversation with PHMSA personnel after
the GPAC meeting.
The GPAC members voted 11-2 in favor of PHMSA's proposed amendments
with respect to test requirements for pressure vessels provided that
PHMSA make the following changes:
Clarify in the NPRM's Sec. 192.153(e)(3) that testing or
inspection of a pressure vessel must take place after being placed on
its supports at its installation location, but may occur prior to tie-
in with station piping.
Clarify in the NPRM's Sec. 192.153(e)(3) that relocated
vessels must meet current design and construction requirements, be
retested by the operator, and be inspected as described in the previous
recommendation, to ensure there are no injurious defects.
Clarify in a new Sec. 192.153(e)(4) that the retesting
requirements applicable to pressure vessels do not apply to those
pressure vessels that are used for temporary maintenance and repair
activities, such as portable launcher or receivers, temporary odorant
tanks, blow down equipment, and other similar equipment, but they must
be inspected for safety and integrity prior to usage.
Two GPAC members representing EDF and PST voted against the
proposed amendments, expressing concern that the retroactivity
prohibition at 49 U.S.C. 60104(b) prohibits PHMSA from applying a
revised test factor to existing pressure vessels. During the meeting,
PHMSA committed to the GPAC members that it would consider the
application of 49 U.S.C. 60104(b)'s prohibition to the changes proposed
in the NPRM.
INGAA, AGA, APGA, API, and GPA Midstream submitted joint
supplemental comments after the GPAC Meeting supporting the GPAC
recommendation and asserting that the proposed PSR amendments did not
violate the 49 U.S.C. 60104(b) retroactivity prohibition. GPA Midstream
separately submitted supplemental comments on that statutory
retroactivity prohibition, explaining by reference to its legislative
history, contemporaneous DOT interpretation of the relevant statutory
language, and subsequent PHMSA interpretations of the same that 49
U.S.C. 60104(b) prohibits only generically-applicable, retroactive
standards imposing new compliance burdens on relevant pipelines. Here,
in contrast, GPA Midstream contended the NPRM's proposed revisions to
Sec. 192.153(e) would relieve regulatory burdens and operators would
have to take no action to be in full compliance with the amended Sec.
192.153(e).
3. PHMSA Response
After considering the comments and the GPAC, PHMSA is adopting the
proposed testing requirements for pressure vessels subject to certain
amendments to the proposed rule with respect to test requirements for
pressure vessels in Sec. 192.153. The final rule adopts the revision
to Sec. 192.153(e)(1), which specifies that a prefabricated unit or
pressure vessel that is installed after July 13, 2004 is not subject to
the strength testing requirements at Sec. Sec. 192.505(b) provided it
has been tested in accordance with Sec. 192.153(a) or (b) and with a
test factor of at least 1.3 times the intended MAOP, consistent with
the hydrostatic pressure test factors in section VIII, division 1 of
the ASME BPVC. The final rule also adds a footnote to table 1 to the
Sec. 192.619(a)(2)(ii) MAOP requirements specifying that the factor
for establishing the MAOP of a prefabricated unit or pressure vessel
installed after July 14, 2004 is 1.3 times the MAOP. These changes
ensure that an operator of a pressure vessel designed and
hydrostatically tested in accordance with section VIII, division 1 of
the ASME BPVC since the incorporation by reference of the 2001 edition
of that document is compliant with the PSR. This allows an operator of
a pressure vessel designed and hydrostatically tested in accordance
with section VIII, division 1 of the ASME BPVC to operate it at an MAOP
equal to its design pressure in most instances. PHMSA notes that if the
pressure vessel is tested at factor lower than 1.3 times the MAWP under
a pneumatic test or under section VIII division 2 of the ASME BPVC, the
MAOP of the pipeline must be
[[Page 2230]]
established such that the test pressure is 1.3 times the MAOP or
greater.
PHMSA understands the administrative record shows that this
rulemaking's revision of the pressure test factors at Sec. 192.153
does not adversely affect the safety of pressure vessels designed,
constructed, and tested in accordance with the 2001 and subsequent
editions of the ASME BPVC, and designed, tested, constructed, and
operated in accordance with the PSR. PHMSA therefore disagrees with
PST's assertion that the ORNL report does not contribute to the
technical justification for that change. PST is correct to note that
the ORNL report compares the 1992 and 2015 editions of the ASME BPVC,
and that other changes have taken place within the intervening editions
of that standard (including the 2007 version currently incorporated by
reference in the PSR). However, the ORNL report did not provide only a
top-level statement of safety equivalence between the 1992 and 2015
editions of the ASME BPVC; it also evaluated the contributions to that
ultimate conclusion from each of the material elements of the 1992 and
2015 editions ASME BPVC--including the effects of a reduction in the
hydrostatic pressure test factor in ASME BPVC section VIII, division 1
from 1.5 times the MAWP to 1.3 times the MAWP.\58\
---------------------------------------------------------------------------
\58\ ORNL report at Table 9.2 (summarizing Section 7.1.2.1 of
the ORNL report on the safety contribution of hydrostatic test
factors in different editions of ASME BPVC section VIII, division
1).
---------------------------------------------------------------------------
The ORNL report predicated its top-level conclusion of safety
equivalence across the 1992 and 2015 editions of the BPVC section VIII,
division 1, notwithstanding their different hydrostatic pressure test
factors, in part on certain shared features. The most important of
those features was that both editions' hydrostatic pressure test
factors yield hydrostatic pressure testing limits that ensure primary
membrane stresses remain at or below plastic collapse stress limits for
a pressure vessel, thereby reducing the risk of permanent distortion
that would result in rejection of the pressure vessel at qualification.
Other features shared between the 1992 and 2015 editions of BPVC
section VIII, division 1 contributing to ORNL's safety equivalence
finding include the following: Pressure testing by an authorized
inspector at qualification verifying leak-tight integrity and the
absence of gross deformations and anomalies indicative of design
errors, material defects, or weld defects; pressure testing after
fabrication verifying leak-tight integrity and the absence of gross
deformations and anomalies indicative of design errors, material
defects, or weld defects; and overpressure protection in the event of
design basis heat exposure ensuring that maximum overpressure does not
exceed 1.3 MAWP.
Each of the features listed above are also shared by the 2007
edition of the BPVC section VIII, section 1 incorporated by reference
in the PSR, notwithstanding any other differences between that edition
and the 1992 and 2015 editions evaluated in the ORNL report. Like the
1992 and 2015 editions, the various design requirements of the 2007
edition of the ASME BPVC ensure that plastic stresses on a pressure
vessel remain at or below plastic collapse stress limits to avoid
permanent distortion. And like the 1992 and 2015 editions, the 2007
edition backstops that design basis by qualified inspections to
identify defects, post-fabrication pressure testing, and overpressure
protection from a design basis heat exposure. Insofar as ORNL
determined that these shared features contributed to its top-level
conclusion of safety equivalence between the 1992 and 2015 editions of
the ASME BPVC, PHMSA understands them to support its conclusion in this
final rule that that a lower (1.3) test factor will not adversely
affect safety.
PHMSA also submits that other elements of this final rule and the
PSR's comprehensive safety regime support the conclusion that lowering
the test factor to 1.3 will not adversely affect safety. The
applicability of the ASME BPVC in the PSR is limited to the design,
testing and fabrication of pressure vessels. On the other hand, the PSR
applies additional requirements throughout the lifecycle of a pressure
vessel to ensure its continued integrity and safe operation. These
requirements pertain to construction (subpart G), corrosion control
(subpart I), testing (subpart J), operation (subpart L), maintenance
(subpart M), and integrity management (subparts O and P) standards.
Further, even with respect to design and installation standards that
are the focus of ASME BPVC section VIII, division 1, PSR requirements
provide additional assurance that stresses remain within safe limits.
For example, Sec. 192.201(a)(2)(i) requires overpressure protection
devices be set to discharge at 1.1 times MAOP or at a pressure
producing a hoop stress of 75 percent of SMYS, whichever is lower--a
requirement that is more conservative than analogous overpressure
specifications in the ASME BPVC referenced in the ORNL report.
Similarly, the ASME BPVC does not specify a minimum pressure test
duration. In contrast, the PSR at subpart J requires a minimum pressure
test durations of 8 hours (Sec. 192.505(c)), 4 hours (Sec.
192.505(d)), 1 hour (Sec. 192.507(c)), or with a procedure sufficient
to ensure discovery of all potentially hazardous leaks (Sec. 192.509).
PHMSA further notes that exemption in this final rule from subpart
J's minimum pressure duration requirements are consistent with that
conclusion. Prior to the changes adopted by this final rule, if an
operator tested a pressure vessel to 1.3 times the MAOP consistent with
section VIII, division 1 of the ASME BPVC rather than 1.5 times the
MAOP, it would not comply with the PSR. An operator of such a vessel
would need to reduce the MAOP of the pressure vessel such that the test
pressure is 1.3 times the reduced MAOP, retest the vessel to 1.5 times
the MAOP, or replace the pressure vessel entirely. Likewise, a pressure
vessel that was not tested for a duration specified in subpart J would
need to be retested or replaced to remain in compliance. While
retesting or replacing existing pressure vessels with a longer test
duration or higher test factor could conceivably decrease the risk of
an overpressure event causing a vessel failure on affected pipelines,
PHMSA understands any such safety benefit could be speculative;
incident reports indicate that pressure vessel failure has not been an
issue on existing vessels in-service.
This is further supported by the conclusions of the ORNL report
with respect to the hydrostatic pressure testing limits described
above. Further, any potential safety benefit from retesting or
replacing pressure vessels already in service would need to be weighed
against new safety risks that may emerge from such activity. And here
PHMSA understands that re-testing and replacing in-service pressure
vessels in pipeline facilities can entail its own safety hazards for
operator personnel due to the mass, volume, and installation location
of a typical pressure vessel compared with other types of pipeline
facilities. Specifically, retesting or replacement of a pressure vessel
requires purging of gas, disconnection from local piping, and likely
removal from service and reinstallation. The pipeline facilities
involved in such efforts may be very heavy and large, which increases
hazards to operator personnel when the pressure vessel or other
equipment is removed from its installation location and prepared for
testing. The layout of compressor stations and other facilities may
exacerbate these safety risks if there
[[Page 2231]]
is limited space to safely remove the pressure vessel or to maneuver
lifting equipment. Each of these steps therefore introduces certain
safety risks to operator personnel performing the work that PHMSA
believes could outweigh any marginal, speculative safety benefit from
re-testing and replacement of previously-installed pressure vessels.
Lastly, as pointed out by multiple comments submitted on the NPRM, such
re-testing and replacement of existing pipe could entail significant
costs and operational disruptions that similarly militate in favor of
the exemption in the final rule.
Finally, PHMSA notes that the ASME BPVC does not specify minimum
test duration requirements and part 192 does not currently require
post-installation inspection of pressure vessels. The final rule's PSR
amendment clarifying that these requirements apply to new, replaced,
relocated, or otherwise changed pressure vessels installed after the
effective date of the final rule are expected to result in an increased
level of safety.
The final rule retains the proposed requirement to inspect pre-
tested pressure vessels after being placed at the vessel's installation
location on its support structure in Sec. 192.153(e)(3). However,
consistent with the GPAC's recommendations, the final rule clarifies
that those inspections may occur prior to the pressure vessel tie-in
on-site with the pipeline. PHMSA appreciates comments that testing
vessels after they have been tied-in to station piping may be
problematic depending on what or how it is being connected. But one of
the risks of transporting pressure vessels and other large components
is damage to the vessel including vessel outlets or its support
structure while it is being moved within the facility itself. Many of
the considerations raised by commenters that may complicate an
inspection likewise raise the likelihood of potential damage during
installation. For example, it would be unusual for a pressure vessel to
be completely inaccessible in a typical compressor station
configuration. In addition, since the Sec. 192.153(e)(3) requirement
applies to new, replaced, and relocated vessels, operators can ensure
access during initial design, construction, and testing stages. The
final rule also clarifies that operators must visually inspect the
steel structure for damage including, at a minimum: Inlets, outlets,
and lifting points. If damage is found, the pressure vessel must be
non-destructively tested, re-pressure tested, or remediated in
accordance with part 192 and ASME BPVC requirements. Test, inspection,
and repair records must be kept for the operational life of the
pressure vessel. These clarifying revisions to Sec. 192.153(e)(3) are
designed to enhance safety, address the most significant concerns
operators had with post-installation inspection, and help ensure that
damage incurred during movements within the facility are detected and
remediated before the pressure vessel is put into service.
PHMSA has also, consistent with the GPAC's recommendations,
clarified when testing and inspection under Sec. 192.153(e)(3) is
required. The final rule clarifies that any pressure vessel that is
temporarily or permanently installed in a pipeline facility must be
inspected for damage as described above unless it has been pressure
tested on its supports at its installation location. This includes
pressure vessels that are pressure tested by the operator prior to
installation when a post-installation pressure test is impracticable
(Sec. Sec. 192.505(d) and 192.507(d) in the final rule) and to
pressure vessels where a manufacturer's pressure test is used under
Sec. 192.153(e)(4) in the final rule. This change is consistent with
pretesting authorizations under Sec. 192.507(d) in the final rule or
Sec. 192.505(d) in existing part 192. It preserves the flexibility
provided under those authorizations while the post-installation
inspection ensures that pre-tested components are not damaged after
being tested by the manufacturer or the operator.
The final rule also clarifies design, testing, and inspection
requirements for pressure vessels that are relocated. Consistent with
the GPAC's recommendations, PHMSA is adding a new Sec. 192.153(e)(6)
that clarifies testing and inspection requirements for relocating an
existing pressure vessel that has previously been used in service for
permanent installation at a new location in a pipeline facility. An
operator must have documentation that a relocated pressure vessel meets
the design, construction, and testing requirements in place at the time
of relocation and pressure test the pressure vessel. If a pre-
installation pressure test is performed, the operator must inspect the
pressure vessel after installation.
The final rule does not adopt suggestions from commenters to accept
a manufacturer's initial pressure test for all relocated pressure
vessels. PHMSA did not propose specific changes to the initial pressure
testing requirements for relocated, existing pressure vessels. Rather,
the requirements in the final rule for permanently relocated vessels
complement existing part 192 requirements for relocation of existing
facilities with the addition of a new, general requirement in Sec.
192.153(e)(3) to inspect pressure vessels that are not pressure tested
in place. Using a manufacturer's initial pressure test of an existing
vessel raises safety concerns because the vessel could have been
subject to corrosion, fatigue, external force damage, and other threats
to the vessel's integrity during its prior operational life or during
transportation to the new facility.
The GPAC's discussion noted that operators commonly use such
temporary devices for temporary launchers and receivers for integrity
assessments and to reduce methane emissions during blowdowns (natural
gas is predominately methane, a greenhouse gas). PHMSA did not intend
to impair the use of pressure vessels that are relocated temporarily in
order to perform maintenance, repair, or emergency-response-related
tasks. To prevent this unintended result, PHMSA is incorporating a new
Sec. 192.153(e)(4)(ii) to allow the use of a manufacturer's initial
test of a pressure vessel temporarily installed in a pipeline facility
to complete a testing, integrity assessment, repair, odorization, or
emergency response-related task, including noise or pollution
abatement. This revision addresses temporary and mobile pressure
vessels that were discussed during the GPAC meeting, including portable
launcher or receivers, temporary odorant tanks, mobile blow down
equipment, and other similar equipment. This change reduces barriers to
using temporary equipment to perform integrity assessment, maintenance,
and pollution mitigation-related tasks (provided the equipment meets
the MAOP, design, and inspection requirements in part 192) and thereby
is expected to result in greater efficiency for operators and safety
and environmental benefits associated with encouraging inspections and
repairs. These devices are subject to the new general requirement in
Sec. 192.153(e)(3)(ii) to inspect pressure vessels that are not
pressure tested in place after installation. Reducing regulatory
burdens associated with performing maintenance, repair, emergency
response, and pollution abatement tasks could result in safety and
environmental benefits by making such actions more attractive to
operators.
To prevents misuse of this flexibility, a pressure vessel that is
installed under Sec. 192.153(e)(4)(ii) must be removed when the task
it is associated with is completed. Operators should define the
procedures for employing temporary or mobile pressure vessels in their
written procedure manuals. The final rule
[[Page 2232]]
requires operators to submit a notification to PHMSA and applicable
State pipeline safety authorities in accordance with Sec. 192.18 if a
temporary pressure vessel must be left in place for longer than 30
days; however, PHMSA does not reference this section in Sec. 192.18(c)
and therefore the objection process and advance notice requirements do
not apply. Likewise, Sec. 192.153(e)(5) clarifies that an operator is
not required to pressure test a pressure vessel that is temporarily
removed from a facility to perform a maintenance task and later re-
installed at the same location. However, the re-installed pressure
vessel must be inspected in accordance with Sec. 192.153(e)(3)(ii)
after it is re-installed. Generally, PHMSA does not consider small
movements within the same location (e.g. within a compressor station)
with no other operational changes as a relocation, however the operator
should inspect the vessel for damage after installation.
PHMSA has considered the comments by PST and members of the GPAC
regarding the nonapplication requirement and finds the revisions to 49
CFR 192.153(e) are not inconsistent with 49 U.S.C. 60104(b). Section
60104(b) provides that a ``design, installation, construction, initial
inspection, or initial testing standard does not apply to a pipeline
facility existing when the standard is adopted.'' Under the revised
Sec. 192.153, operators of existing pressure vessels that meet minimum
testing requirements will not be required to take any additional action
to comply. While the revised section requires that components be
pressure tested with a test factor of at least 1.3 times MAOP, the
current Sec. 192.153(e) already required such testing at even higher
pressures; in other words, a pressure vessel compliant with the
existing Sec. 192.153(e) would also be compliant with Sec. 192.153(e)
as revised by this final rule. The revisions to the PSR, therefore,
cannot be said to impose a new standard on existing facilities in
conflict with 49 U.S.C. 60104(b).
In addition, as described in the preamble to the NPRM, the
amendment to 49 CFR 192.153(e) responds to a petition for
reconsideration of the Miscellaneous Rule.\59\ This final rule
addresses the issues raised by the petition challenging the addition of
Sec. 192.153(e) in the Miscellaneous Rule pursuant to the
reconsideration procedures in part 190. The petition for
reconsideration of the Miscellaneous Rule argues PHMSA's modifications
to Sec. 192.153 were not merely clarifications regarding the required
testing standard for pressure vessels as PHMSA stated in the
Miscellaneous Rule, but rather were departures from the testing
standard for pressure vessels in the ASME BPVC standard that was
incorporated in the regulations at the time. PHMSA maintains that the
Miscellaneous Rule merely clarified the required testing standard for
pressure vessels, but understands there was ambiguity in the
regulations regarding the testing standard for pressure vessels before
the Miscellaneous Rule was passed and that the Miscellaneous Rule
codified a higher testing standard than many operators reasonably
believed was compliant with the regulations at the time. Also, based on
the discussion above, PHMSA was able to verify that the provisions in
the final rule will not adversely affect safety. PHMSA is therefore
allowing pressure vessels tested in accordance with the 1.3 test factor
after 2004 to continue operating without retesting in order not to
penalize conduct some operators believed complied with the PSR at the
time.
---------------------------------------------------------------------------
\59\ Available in docket No. PHMSA-2010-0026 and the docket for
this final rule.
---------------------------------------------------------------------------
Lastly, because PHMSA understands the PSR revisions in this final
rule obviate the need for its unpublished October 27, 2015 letter to
INGAA announcing a stay of enforcement pertaining to certain pressure
vessels in violation of Sec. Sec. 192.153(e) and 192.505(b), it
withdraws that document as of the effective date of this final rule.
This letter is also available in the docket for this final rule.
I. Welding Process Requirement (Section 192.229)
1. PHMSA's Proposal
Section 192.229(b) currently bars welders from welding with a
welding process if they have not engaged in welding with that same
process within the previous six months. GPTC submitted a petition for
rulemaking requesting PHMSA revise Sec. 192.229(b) to 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 (Std) 1104.\60\ API Std 1104 is the
primary standard for welding steel piping and for testing welds on
steel pipelines, and covers the requirements for welding and
nondestructive testing of pipeline welds. API Std 1104 is used within
part 192 requirements for qualifying welders, welding procedures, and
welding operators, and interpreting the results of non-destructive
tests.
---------------------------------------------------------------------------
\60\ Docket No. PHMSA-2014-0015.
---------------------------------------------------------------------------
GPTC also noted that the 6-month frequency requirement for the
welding process requirement at Sec. 192.229(b) is different than other
requirements in Sec. 192.229(c)(1) and (d)(2) governing welder
requalification frequency. Those welder requalification requirements
demand requalification within the preceding 7\1/2\ months, but at least
twice each calendar year. GPTC pointed out that this discrepancy
between welder process requirements and welder requalification
requirements obliged operators either to maintain alternative
recordkeeping procedures for the process requirement or perform welds
to comply with both the process requirement and the requalification
requirements on a 6-month interval. In other words, if a welder wishes
to use the same weld to comply with both requirements, they are unable
to benefit from the more flexible welder requalification requirements
at Sec. 192.229(c)(1) and (d)(2).
PHMSA proposed in the NPRM 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 Std 1104. This change would provide
operators some flexibility in scheduling welding activities to maintain
welder requalification. PHMSA agrees with GPTC that the proposed
revision is more consistent with Sec. 192.229(d)(2). This is
potentially beneficial for welders who weld relatively infrequently.
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.
2. Summary of Public Comments
AmeriGas, AIPRO, FreedomWorks, NPGA, Oleksa and Associates, and SPP
supported the proposed requalification scheduling for welders. Oleksa
and Associates stated that there will be no negative impact on pipeline
safety. FreedomWorks stated that the changes would allow welders, many
of whom are self-employed freelancers, greater flexibility in their
trade. AIPRO commented that the changes would establish regulatory
expectations and create more scheduling opportunity for vendors to
perform the welding tests and for companies to comply with the
standard. The GPAC voted unanimously
[[Page 2233]]
in favor of PHMSA's proposed amendments regarding the welding process
requirement.
3. PHMSA Response
Based on the comments and the GPAC recommendations, PHMSA has
adopted this amendment as proposed. This change will streamline
compliance and recordkeeping activities related to Sec. 192.229(b) and
will not have a detrimental impact on safety.
J. Pre-Test Applicability (Section 192.507)
1. PHMSA's Proposal
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 of 30 percent or more of SMYS if a post-
installation test is not practicable. PHMSA proposed in the NPRM to add
a new paragraph (d) to Sec. 192.507 to extend this authorization to
steel pipelines operated at a hoop stress less than 30 percent of SMYS
and at or above 100 psig.\61\
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\61\ ``Pounds per square inch gauge'' refers to internal
pressure relative to outside atmospheric pressure.
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The NPRM's proposed revision is in response to a petition for
rulemaking submitted by GPTC for PHMSA to relocate the pre-installation
strength testing requirement at Sec. 192.505(d) to the general test
requirements in Sec. 192.503 to permit broader application of this
authorization. GPTC argued this change would permit operators to use
pre-tested pipe and fabricated units in applications outside of higher
stress transmission pipelines. GPTC further asserted that as this
provision is currently applicable only to higher-stress pipelines
operating at a hoop stress at or greater than 30 percent of SMYS,
extending the broader pre-testing provision to lower-stress pipelines
would not increase pipeline safety risks. Rather, GPTC predicted this
proposed change will provide greater flexibility and efficiency for
operators of lower-stress pipelines, especially during maintenance
activities.
Instead of adding pre-testing provisions to the general
requirements at Sec. 192.503 as suggested by the GPTC petition, PHMSA
proposed in the NPRM to add Sec. 192.507(d) to permit pre-testing on
steel pipelines operating at a hoop stress less than 30 percent of SMYS
and at or above 100 psig. The proposal did not extend pre-testing
provisions to pipelines operating below 100 psig (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 requested comments on whether it is appropriate
to extend pre-testing provisions to such facilities, and solicited
proposed requirements that should apply if pre-testing provisions are
extended to such facilities.
2. Summary of Public Comments
AmeriGas, NPGA, and SPP supported the proposed changes to Sec.
192.507 to allow operators to extend the authorization for pre-testing
fabricated assemblies to include steel pipelines that operate at a hoop
stress less than 30 percent of SMYS and at or above 100 psig.
Similarly, PST commented that they did not object to extending the pre-
testing provisions to lower stress pipelines as proposed in the NPRM.
AGA et al., National Fuel, and Oleksa and Associates recommended
that PHMSA consider extending the pre-testing allowance to other
pipelines that also pose less of a safety risk. Specifically, they
recommended that PHMSA extend the allowance for pre-tested short
segments of pipe and fabricated units to steel pipelines that operate
at pressures less than 100 psig (Sec. 192.509), plastic pipelines
(Sec. 192.511), and service lines (Sec. 192.513) to provide clarity
and consistency within the regulations. These commenters suggested the
addition of enabling regulatory text. Oleksa and Associates agreed with
these commenters, stating that the rationale that applies to permitting
pre-tested pipe on steel pipelines operating at a stress less than 30
percent of SMYS and at or above 100 psig applies in the same way to
pipelines operating below 100 psig, service lines, and plastic
pipelines. They suggested that the simplest way to accomplish this is
to modify the wording in Sec. 192.503.
Similarly, NAPSR opposed the proposed revision unless it is revised
to allow the use of pre-tested pipe for main repairs under 100 psig.
Specifically, NAPSR commented that it may be impracticable to pressure
test Type B gathering lines and mains post-installation. They commented
that if pre-tested pipe is allowed for systems that operate above 100
psig and above 30 percent SMYS, then pre-tested pipe should also be
allowed for all pipe that operates below 100 psig and low stress pipe.
NAPSR believes that most operators use pre-tested pipe for main and
Type B gathering line repairs as a standard practice; that pipe is soap
tested and visually inspected for leaks after installation. They stated
that the proposed change in the NPRM could unnecessarily restrict
operators from safely and quickly repairing damages, and that
distribution operators could potentially experience prolonged outages
(especially in cold weather) and increased repair times and cost if
pre-tested pipe is not allowed.
AGA et al. commented that in 2019, distribution system operators
reported 84,608 leaks caused by excavation damage on their Gas
Distribution Annual Reports. Assuming each excavation damage related
leak required a pressure test, and assuming a cost of $200 per post-
installation pressure test, they stated that the cost would be nearly
$17 million annually to pressure test pipe replaced due to excavation
damage alone. National Fuel's comment included a similar calculation
and estimated $8.8 million in cost savings if pre-tested pipe is
allowed for such repairs. These commenters asserted that the use of
pre-tested pipe would significantly reduce these costs as operators
could pre-test full joints or coils of pipe for use on multiple short
segment replacements and repairs without compromising safety.
National Fuel commented that extending pre-testing to distribution
lines would allow the use of pre-tested pipe for short segment
replacements for leak repairs, excavation damage repairs and
replacement of visually questionable welds or plastic fusion joints.
They noted that without this change operators are required to test
short replacement segments in place, which is inefficient, time
consuming, and often results in extended shutdown durations and
inconvenience to customers. They further stated that based on current
regulatory language, an excavation damage repair that involves
replacement of two feet of plastic distribution main requires that the
operator: (1) Fuse end caps on each end of the replacement segment, (2)
pressure test the pipe in place for the required duration, (3) remove
the end caps, (4) tie-in the replacement segment by electrofusion or
coupling, and (5) purge, gas and soap test the joints. They stated that
allowing the use of pre-tested pipe would significantly reduce the
repair time and costs to complete the repair and would still result in
a pipe segment that is both strength tested and leak tested to ensure
an equal level of safety while limiting interruptions to customers.
AGA et al. recommended that PHMSA remove the term ``hydrostatic''
from the test requirements for short segments of pipe and pre-
fabricated units from Sec. 192.507 because natural gas, inert gas, and
air are also allowable test media for pipelines operating at a
[[Page 2234]]
hoop stress less than 30 percent of SMYS under Sec. 192.503(c).
The GPAC voted unanimously in favor of PHMSA's proposed PSR
amendments regarding the welding process requirement but recommended
removing the word ``hydrostatic'' from the proposed Sec. 192.507(d).
3. PHMSA Response
Based on the comments received and the recommendation of the GPAC,
the final rule adopts the amendments related to pre-testing fabricated
assemblies and short segments of pipe as proposed in the NPRM, except
that PHMSA has removed the term ``hydrostatic'' from the new Sec.
192.507(d). PHMSA agrees that removing the term ``hydrostatic'' is
appropriate since other test media other than water are approved for
use in that new section.
The final rule does not extend the authorization in Sec. 192.507
(as revised) for pre-tested segments of pipe and fabricated assemblies
beyond steel pipe with an MAOP producing a hoop stress less than 30
percent of SMYS but at or above 100 psig. Operators must still perform
leak tests after installing fabricated units and short segments of pipe
installed on such pipelines. The remaining categories in subpart J
(metallic pipe with an MAOP less than 100 psig, plastic pipe, and
service lines) generally represent distribution lines rather than
transmission lines. It is not clear that there is adequate safety
justification for extending the pre-testing allowance to these
categories of lines due to the proximity of such facilities to
customers and the differences in design, construction, inspection, and
testing requirements for such facilities compared with higher-pressure
transmission lines. For example, welds on higher-pressure metallic
lines require inspection with non-destructive testing techniques under
Sec. 192.241, while plastic pipe joints and welds on lower-pressure
metallic lines can be visually inspected instead. The leak tests
required for lower-pressure lines in subpart J are, therefore,
necessary to ensure the leak-tight integrity of welds and joints on
such lines. Commenters did not suggest alternative inspection
requirements or other conditions for using pre-tested pipe and
fabricated units on such pipelines. PHMSA therefore determined that
additional analysis is necessary to consider the safety effects of
extending the pre-testing allowance to such facilities, and what, if
any, additional conditions may be necessary. The GPAC voted unanimously
in favor of this recommended approach. PHMSA may consider this issue in
future rulemaking.
PHMSA notes that Sec. Sec. 192.509, 192.511, and 192.513 require
only a leak test. NAPSR presented a scenario where, for a replacement
repair, an operator installed pre-tested pipe and then performed a leak
test after installation. The leak test described in this scenario meets
the post-installation leak test requirement in Sec. 192.509, provided
that the operator's test procedure ensures the discovery of all
potentially hazardous leaks.
IV. 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 80 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.
The National Technology Transfer and Advancement Act of 1995 (Pub.
L. 104-113; NTTAA) 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, the Office of Management and Budget (OMB)
issued Circular A-119 \62\ 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.
---------------------------------------------------------------------------
\62\ OMB, Circular A-119, ``Federal Participation in the
Development and Use of Voluntary Consensus Standards and in
Conformity Assessment Activities'' (Jan. 27, 2016). Circular A-119
and revisions thereto are available at https://www.whitehouse.gov/omb/information-for-agencies/circulars/.
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Accordingly, PHMSA is responsible 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.
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. 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. 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.\63\
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\63\ 79 FR 66278.
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To meet these obligations 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 and is discussed in greater detail in
section I.1 of this preamble. The ASTM standards are available at
https://www.astm.org/READINGLIBRARY/ and are discussed in greater
detail in section G.1 of this preamble. PHMSA will also 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]. PHMSA also notes
that standards incorporated by reference in the PSR can be obtained
from the organization developing each standard. Section 192.7 provides
the contact information for each of those standard-developing
organizations.
V. Regulatory Analyses and Notices
A. Legal Authority for This Rulemaking
This rule is published under the authority of the Federal Pipeline
Safety Law (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, Sec. 60102(l) of the Federal Pipeline
Safety Law 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 Sec. 60102 to the
[[Page 2235]]
Administrator of PHMSA in 49 CFR 1.97.
B. Executive Order 12866 and DOT Rulemaking Procedures
E.O. 12866, ``Regulatory Planning and Review,'' \64\ requires
agencies to regulate in the ``most cost-effective manner,'' to make a
``reasoned determination that the benefits of the intended regulation
justify its costs,'' and to develop regulations that ``impose the least
burden on society.'' E.O. 12866 and DOT regulations governing
rulemaking procedures at 49 CFR part 5 require that PHMSA submit
``significant regulatory actions'' to OMB for review. This rule is
considered significant under Sec. 3(f) of E.O. 12866, and was reviewed
by OMB. It is also significant under the DOT's rulemaking procedures at
49 CFR part 5.
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\64\ 58 FR 51735; Oct. 4, 1993.
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Similarly, DOT regulations at Sec. 5.5(f)-(g) require that
regulations issued by PHMSA and other DOT Operating Administrations
``should be designed to minimize burdens and reduce barriers to market
entry whenever possible, consistent with the effective promotion of
safety'' and should generally ``not be issued unless their benefits are
expected to exceed their costs.''
E.O. 12866 and DOT implementing regulations at 49 CFR 5.5(i) also
require PHMSA to provide a meaningful opportunity for public
participation, which also reinforces requirements for notice and
comment under the Administrative Procedure Act (5 U.S.C. 551, et seq.).
Therefore, in the NPRM, PHMSA sought public comment on its proposed
revisions to the PSR and the preliminary cost and cost savings analyses
in the Preliminary RIA, as well as any information that could assist in
quantifying the benefits of this rulemaking. Those comments are
addressed in this final rule, and additional discussion about the
economic impacts of the final rule are provided within the final RIA
posted in the rulemaking docket.
PHMSA estimated that this final rule 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 final rule will result in annualized cost
savings of approximately $129.8 million per year, based on a 7 percent
discount rate. Most of the quantified cost savings in the final rule
are from the revisions to farm tap requirements and the revised
atmospheric corrosion reassessment interval for distribution service
lines. The final RIA in the rulemaking docket analyzes these economic
impacts in detail.
C. Executive Order 13771, ``Reducing Regulation and Controlling
Regulatory Cost''
This final rule is an E.O. 13771 \65\ deregulatory action. Details
on the estimated cost savings of this final rule can be found in the
rule's economic analysis within the RIA in the rulemaking docket.
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\65\ 82 FR 9339 (Feb. 3, 2017).
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D. Executive Order 13132--``Federalism''
PHMSA analyzed this final rule in accordance with E.O. 13132.\66\
E.O. 13132 requires agencies to assure meaningful and timely input by
State and local officials in the development of regulatory policies
that may have ``substantial direct effects on the States, on the
relationship between the national government and the States, or on the
distribution of power and responsibilities among the various levels of
government.''
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\66\ 64 FR 43255 (Aug. 10, 1999).
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This final rule 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 final rule also does not impose
substantial direct compliance costs on State and local governments.
The final rule could have preemptive effect because the Federal
Pipeline Safety Law, specifically 49 U.S.C. 60104(c), prohibits certain
State safety regulation of interstate pipelines. Under the Federal
Pipeline Safety Law, States may 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 final rule is
limited to the minimum level necessary to achieve the objectives of the
Federal Pipeline Safety Law under which the final 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''
PHMSA analyzed this final rule in accordance with the principles
and criteria in E.O. 13175 \67\ and DOT Order 5301.1, ``Department of
Transportation Programs, Polices, and Procedures Affecting American
Indians, Alaska Natives, and Tribes.'' E.O. 13175 requires agencies to
assure meaningful and timely input from Tribal government
representatives in the development of rules that significantly or
uniquely affect Tribal communities by imposing ``substantial direct
compliance costs'' or ``substantial direct effects'' on such
communities or the relationship and distribution of power between the
Federal Government and Tribes. PHMSA assessed the impact of the final
rule on Indian Tribal communities and determined that it would not
significantly or uniquely affect Tribal communities or Indian Tribal
governments. Therefore, the funding and consultation requirements of
E.O. 13175 do not apply. PHMSA received no comments to the effect that
this rulemaking would have Tribal implications.
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\67\ 65 FR 67249 (Nov. 6, 2000).
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F. Executive Order 13211--``Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use''
E.O. 13211 \68\ requires Federal agencies to prepare a Statement of
Energy Effects for any ``significant energy action.'' Under E.O. 13211,
a ``significant energy action'' is defined as any action by an agency
(normally published in the Federal Register) that promulgates, or is
expected to lead to the promulgation of, a final rule or regulation
(including a notice of inquiry, ANPRM, and NPRM) that: (1)(i) Is a
significant regulatory action under E.O. 12866 or any successor order,
and (ii) is likely to have a significant adverse effect on the supply,
distribution, or use of energy; or (2) is designated by the
Administrator of the Office of Information and Regulatory Affairs as a
significant energy action.
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\68\ 66 FR 28355 (May 22, 2001).
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This final rule is not a ``significant energy action'' under E.O.
13211. It is not likely to have a significant adverse effect on supply,
distribution, or energy use; rather, it is expected to reduce
regulatory burdens on the natural gas pipeline sector without adversely
affecting safety. Further, the Office of Information and Regulatory
Affairs has not designated this final rule as a significant energy
action.
G. Regulatory Flexibility Act and Executive Order 13272
The Regulatory Flexibility Act (5 U.S.C. 601 et seq.), as
implemented by E.O. 13272, ``Proper Consideration of Small Entities in
Agency
[[Page 2236]]
Rulemaking,'' \69\ and Sec. 5.13(f) of DOT regulations, requires
Federal regulatory agencies to prepare a Final Regulatory Flexibility
Analysis (FRFA) for any final rule subject to notice-and-comment
rulemaking under the Administrative Procedure Act unless the agency
head certifies that the rule will not have a significant economic
impact on a substantial number of small entities.
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\69\ 68 FR 7990 (Feb. 19, 2003).
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PHMSA has determined that the cost-savings in the final rule may
result in significant economic impacts on a substantial number of small
entities. These impacts on regulated entities are beneficial. PHMSA has
included a FRFA within the final RIA posted 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.
Pursuant to 44 U.S.C. 3506(c)(2)(B) and 5 CFR 1320.8(d), PHMSA is
required to provide interested members of the public and affected
agencies with an opportunity to comment on information collection and
recordkeeping requests. PHMSA expects this final rule to impact the
information collections described below.
PHMSA will submit an information collection revision request to OMB
for approval based on the requirements in this final rule. The
information collections are contained in the PSR. 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 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 28 fewer gas distribution
incident reports, and 14 fewer gas transmission reports. Operators
currently spend 12 hours completing each incident report. Therefore,
PHMSA expects to eliminate 42 responses and 504 hours from this
information collection per year 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: 259.
Total Annual Burden Hours: 3,108.
Frequency of Collection: On Occasion.
2. Title: Annual and Incident 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 MFF 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. In the currently-approved information collection, it is
estimated that PHMSA currently receives, on average, 8,300 MFF 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 PSR require operators of gas distribution pipelines
to develop and implement IM programs.
PHMSA proposed to eliminate this requirement for master meter
operators. Based on the currently approved information collection,
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 attributable to these 5,461 existing
master meter operators, saving 141,986 hours of burden annually.
Affected Public: Natural Gas Pipeline Operators.
Annual Reporting and Recordkeeping Burden:
Total Annual Responses: 3,882.
Total Annual Burden Hours: 723,192.
Frequency of Collection: On occasion.
4. Title: Gas Distribution Annual Report.
OMB Control Number: 2137-0629.
Current Expiration Date: 10/31/2021.
Abstract: The PSR require distribution operators to prepare and
submit annual reports with summary information on their pipeline
infrastructure. PHMSA proposed to shift the mechanical fitting failure
form requirements to a count of hazardous leaks involving a failure of
a mechanical joint on the distribution annual report form. PHMSA
estimates that it will take gas distribution operators approximately 30
minutes (0.5 hours; calculated as 13,075 mechanical joint failures
divided by 1,446 operators times 3 minutes per mechanical joint
failure) to add this information to the annual report. As a result, the
burden for this information collection will increase by approximately
723 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: 25,305.
Frequency of Collection: Annually.
I. Unfunded Mandates Reform Act of 1995
Unfunded Mandates Reform Act (2 U.S.C. 1501 et seq.) requires
agencies to assess the effects of Federal regulatory actions on State,
local, and Tribal governments, and the private sector. For any NPRM or
final rule 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 1996 dollars 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.
PHMSA prepared a final RIA and determined that this final rule does
not impose enforceable duties on State, local, or Tribal governments or
on the private sector of $164 million in 2019 dollars or more in any
one year. A copy of the final RIA is available for review in the docket
of this rulemaking.
[[Page 2237]]
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 rule in accordance with NEPA, NEPA implementing
regulations (40 CFR parts 1500-1508), and DOT Order 5610.1C. PHMSA
prepared a draft environmental assessment (EA) for the NPRM and posted
it in the rulemaking docket; PHMSA received no comments on the draft
EA. For this final rule, PHMSA has prepared a Final Environmental
Assessment (EA) and has determined that this final rule will not
significantly affect the quality of the human environment. The final EA
for this final rule is available in the docket.
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
49 CFR Part 191
Pipeline reporting requirements, Integrity management, Pipeline
safety, Gas gathering.
49 CFR Part 192
Incorporation by reference, Pipeline safety, Fire prevention,
Security measures.
In consideration of the forgoing, PHMSA is amending 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: 30 U.S.C. 185(w)(3), 49 U.S.C. 5121, 60101 et seq.,
and 49 CFR 1.97
0
2. In Sec. 191.3, 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. For adjustments for inflation observed in calendar year 2021
onwards, changes to the reporting threshold will be posted on PHMSA's
website. These changes will be determined in accordance with the
procedures in appendix A to part 191.
* * * * *
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 a production pipeline or a gathering
line other than a regulated gathering line as determined in Sec.
192.8.
Sec. 191.12 [Removed and Reserved]
0
4. Remove and reserve Sec. 191.12.
0
5. Appendix A to part 191 is added to read as follows:
Appendix A to Part 191--Procedure for Determining Reporting Threshold
I. Property Damage Threshold Formula
Each year after calendar year 2021, the Administrator will
publish a notice on PHMSA's website announcing the updates to the
property damage threshold criterion that will take effect on July 1
of that year and will remain in effect until the June 30 of the next
year. The property damage threshold used in the definition of an
Incident at Sec. 191.3 shall be determined in accordance with the
following formula:
[GRAPHIC] [TIFF OMITTED] TR11JA21.019
Where:
Tr is the revised damage threshold,
Tp is the previous damage threshold,
CPIr is the average Consumer Price Indices for all Urban Consumers
(CPI-U) published by the Bureau of Labor Statistics each month
during the most recent complete calendar year, and
CPIp is the average CPI-U for the calendar year used to establish
the previous property damage criteria.
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: 30 U.S.C. 185(w)(3), 49 U.S.C. 5103, 60101 et seq.,
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 paragraph (e) introductory text and paragraphs (e)(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. The materials listed in this section
have the full force of law. 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 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) and (c); 192.241(c); and
Item II, Appendix B.
* * * * *
(e) ASTM International (formerly American Society for Testing and
Materials), 100 Barr Harbor Drive, PO Box C700, West Conshohocken, PA
19428, phone: (610) 832-9585, website: https://astm.org.
* * * * *
(11) 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,'' approved February 1, 2019, (ASTM
[[Page 2238]]
F2620), IBR approved for Sec. Sec. 192.281(c) and 192.285(b).
* * * * *
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) and (iv), and (d)(2)(iv);
0
d. In paragraph (e) introductory text add the words ``on or'' after the
word ``produced''; and
0
e. Revise paragraph (e)(4).
The revisions read as follows:
Sec. 192.121 Design of plastic pipe.
* * * * *
(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................................. 0.099 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................................. 0.099 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).
[[Page 2239]]
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................................. 0.099 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 paragraphs (b) 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:
(1) Regularly manufactured butt-welding fittings.
(2) Pipe that has been produced and tested under a specification
listed in appendix B to this part.
(3) Partial assemblies such as split rings or collars.
(4) Prefabricated units that the manufacturer certifies have been
tested to at least twice the maximum pressure to which they will be
subjected under the anticipated operating conditions.
* * * * *
(e) The test requirements for a prefabricated unit or pressure
vessel, 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) A prefabricated unit or pressure vessel installed after July
14, 2004 is not subject to the strength testing requirements at Sec.
192.505(b) provided the component has been 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) A prefabricated unit or pressure vessel must be tested for a
duration specified as follows:
(i) A prefabricated unit or pressure vessel installed after July
14, 2004, but before October 1, 2021 is exempt from Sec. Sec.
192.505(c) and (d) and 192.507(c) provided it has been tested for a
duration consistent with the ASME BPVC requirements referenced in
paragraph (a) or (b) of this section.
(ii) A prefabricated unit or pressure vessel installed on or after
October 1, 2021 must be tested for the duration specified in either
Sec. 192.505(c) or (d), Sec. 192.507(c), or Sec. 192.509(a),
whichever is applicable for the pipeline in which the component is
being installed.
(3) For any prefabricated unit or pressure vessel permanently or
temporarily installed on a pipeline facility, an operator must either:
(i) Test the prefabricated unit or pressure vessel in accordance
with this section and Subpart J of this part after it has been placed
on its support structure at its final installation location. The test
may be performed before or after it has been tied-in to the pipeline.
Test records that meet Sec. 192.517(a) must be kept for the
operational life of the prefabricated unit or pressure vessel; or
(ii) For a prefabricated unit or pressure vessel that is pressure
tested prior to installation or where a manufacturer's pressure test is
used in accordance with paragraph (e) of this section, inspect the
prefabricated unit or pressure vessel after it has been placed on its
support structure at its final installation location and confirm that
the prefabricated unit or pressure vessel was not damaged during any
prior operation, transportation, or installation into the pipeline. The
inspection procedure and documented inspection must include visual
inspection for vessel damage, including, at a minimum, inlets, outlets,
and lifting locations. Injurious defects that are an integrity threat
may include dents, gouges, bending, corrosion, and cracking. This
inspection must be performed prior to operation but may be performed
either before or after it has been tied-in to the pipeline. If
injurious defects that are an integrity threat are found, the
prefabricated unit or pressure vessel must be either non-destructively
tested, re-pressure tested, or remediated in accordance with applicable
part 192 requirements for a fabricated unit or with the applicable ASME
BPVC requirements referenced in paragraphs (a) or (b) of this section.
Test, inspection, and repair records for the fabricated unit or
pressure vessel must be kept for the operational life of the component.
Test records must meet the requirements in Sec. 192.517(a).
(4) An initial pressure test from the prefabricated unit or
pressure vessel manufacturer may be used to meet the requirements of
this section with the following conditions:
(i) The prefabricated unit or pressure vessel is newly-manufactured
and installed on or after October 1, 2021, except as provided in
paragraph (e)(4)(ii) of this section.
(ii) An initial pressure test from the fabricated unit or pressure
vessel manufacturer or other prior test of a new or existing
prefabricated unit or pressure vessel may be used for a component that
is temporarily installed in a pipeline facility in order to complete a
testing, integrity assessment, repair, odorization, or emergency
response-related task, including noise or pollution abatement. The
temporary component must be promptly removed after that task is
completed. If operational and environmental constraints require leaving
a temporary prefabricated unit or pressure vessel under this paragraph
in place for longer than 30 days, the operator must notify PHMSA and
State or local pipeline
[[Page 2240]]
safety authorities, as applicable, in accordance with Sec. 192.18.
(iii) The manufacturer's pressure test must meet the minimum
requirements of this part; and
(iv) The operator inspects and remediates the prefabricated unit or
pressure vessel after installation in accordance with paragraph
(e)(3)(ii) of this section.
(5) An existing prefabricated unit or pressure vessel that is
temporarily removed from a pipeline facility to complete a testing,
integrity assessment, repair, odorization, or emergency response-
related task, including noise or pollution abatement, and then re-
installed at the same location must be inspected in accordance with
paragraph (e)(3)(ii) of this section; however, a new pressure test is
not required provided no damage or threats to the operational integrity
of the prefabricated unit or pressure vessel were identified during the
inspection and the MAOP of the pipeline is not increased.
(6) Except as provided in paragraphs (e)(4)(ii) and (5) of this
section, on or after October 1, 2021, an existing prefabricated unit or
pressure vessel relocated and operated at a different location must
meet the requirements of this part and the following:
(i) The prefabricated unit or pressure vessel must be designed and
constructed in accordance with the requirements of this part at the
time the vessel is returned to operational service at the new location;
and
(ii) The prefabricated unit or pressure vessel must be pressure
tested by the operator in accordance with the testing and inspection
requirements of this part applicable to newly installed prefabricated
units and pressure vessels.
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 alternative written
procedure that has been demonstrated to provide an equivalent or
superior level of safety and 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) to read as follows
Sec. 192.285 Plastic pipe: Qualifying persons to make joints.
* * * * *
(b) The specimen joint must be:
(1) Visually examined during and after assembly or joining and
found to have the same appearance as a joint or photographs of a joint
that is acceptable under the procedure; and
(2) In the case of a heat fusion, solvent cement, or adhesive
joint:
(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;
(ii) Examined by ultrasonic inspection and found not to contain
flaws that would cause failure; or
(iii) Cut into at least 3 longitudinal straps, each of which is:
(A) Visually examined and found not to contain voids or
discontinuities on the cut surfaces of the joint area; and
(B) Deformed by bending, torque, or impact, and if failure occurs,
it must not initiate in the joint area.
* * * * *
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) After January 1, 2022, each remotely inspected rectifier must
be physically inspected for continued safe and reliable operation at
least once each calendar year, but with intervals not exceeding 15
months.
* * * * *
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.
------------------------------------------------------------------------
[[Page 2241]]
* * * * *
(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, but with intervals
not exceeding 39 months.
0
15. In 192.491, revise paragraph (c) to read as follows:
Sec. 192.491 Corrosion control records.
* * * * *
(c) Each operator shall maintain a record of each test, survey, or
inspection required by this subpart in sufficient detail to demonstrate
the adequacy of corrosion control measures or that a corrosive
condition does not exist. These records must be retained for at least 5
years with the following exceptions:
(1) Operators must retain records related to Sec. Sec. 192.465(a)
and (e) and 192.475(b) for as long as the pipeline remains in service.
(2) Operators must retain records of the two most recent
atmospheric corrosion inspections for each distribution service line
that is being inspected under the interval in Sec. 192.481(a)(2).
0
16. 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 mai ntaining the pressure at or
above the test pressure for at least 8 hours.
* * * * *
0
17. 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
18. In Sec. 192.619, revise Table 1 to paragraph (a)(2)(ii) to read as
follows:
Sec. 192.619 Maximum allowable operating pressure: Steel or plastic
pipelines.
* * * * *
(a) * * *
(2) * * *
(ii) * * *
Table 1 to Paragraph (a)(2)(ii)
----------------------------------------------------------------------------------------------------------------
Factors,1 2 segment--
-----------------------------------------------------
Installed before Installed after
Class location (Nov. 12, 1970) (Nov. 11, 1970) Installed on or Converted under
and before July after July 1, Sec. 192.14
1, 2020 2020
----------------------------------------------------------------------------------------------------------------
1....................................... 1.1 1.1 1.25 1.25
2....................................... 1.25 1.25 1.25 1.25
3....................................... 1.4 1.5 1.5 1.5
4....................................... 1.4 1.5 1.5 1.5
----------------------------------------------------------------------------------------------------------------
\1\ For offshore pipeline segments installed, uprated or converted after July 31, 1977, that are not located on
an offshore platform, the factor is 1.25. For pipeline segments installed, uprated or converted after July 31,
1977, that are located on an offshore platform or on a platform in inland navigable waters, including a pipe
riser, the factor is 1.5.
\2\ For a component with a design pressure established in accordance with Sec. 192.153(a) or (b) installed
after July 14, 2004, the factor is 1.3.
0
19. In Sec. 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 as determined in Sec. 192.8
that is not operated as part of a distribution system.
* * * * *
(c) This section does not apply to equipment installed on:
(1) A service line that only serves engines that power irrigation
pumps;
(2) A service line included in a distribution integrity management
plan meeting the requirements of subpart P of this part; or
(3) A service line directly connected to either a production or
gathering pipeline other than a regulated gathering line as determined
in Sec. 192.8 of this part.
0
20. Revise Sec. 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
line or a gathering line other than a regulated onshore gathering line
as determined in Sec. 192.8;
(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
21. 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
22. 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.
[[Page 2242]]
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
23. Remove and reserve Sec. 192.1009.
0
24. In Sec. 192.1015, revise the section heading, and paragraphs (a)
and (b) 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) Elements. A written integrity management plan must address, at
a minimum, the following elements:
(1) Knowledge. The operator must demonstrate knowledge of its
pipeline, which, to the extent known, should include the approximate
location and material of its pipeline. The operator must identify
additional information needed and provide a plan for gaining knowledge
over time through normal activities conducted on the pipeline (for
example, design, construction, operations or maintenance activities).
(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.
(3) Rank risks. The operator must evaluate the risks to its
pipeline and estimate the relative importance of each identified
threat.
(4) Identify and implement measures to mitigate risks. The operator
must determine and implement measures designed to reduce the risks from
failure of its pipeline.
(5) Measure performance, monitor results, and evaluate
effectiveness. The operator must monitor, as a performance measure, the
number of leaks eliminated or repaired on its pipeline and their
causes.
(6) Periodic evaluation and improvement. The operator must
determine the appropriate period for conducting IM program evaluations
based on the complexity of its pipeline and changes in factors
affecting the risk of failure. An operator must re-evaluate its entire
program at least every 5 years. The operator must consider the results
of the performance monitoring in these evaluations.
* * * * *
Appendix B to Part 192 [Amended]
0
25. Amend Appendix B to part 192 as follows:
0
a. In section I.A., remove the entry for ``ASTM D2513-12ae1'' and add
in its place a new entry for ``ASTM D2513'', and
0
b. In Section I.B., remove the entry for ``ASTM D2513-12ae1'' and add
in its place a new entry for ``ASTM D2513''.
Issued in Washington, DC, on January 1, 2021, under authority
delegated in 49 CFR 1.97.
Howard R. Elliott,
Administrator.
[FR Doc. 2021-00208 Filed 1-8-21; 8:45 am]
BILLING CODE 4910-60-P