[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repealed, replaced, or modified, and PHMSA's review of public comments.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Taps'' and the unpublished October 27, 2015 letter to the Interstate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]
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Estimated cost
Category savings
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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
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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.
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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).
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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.
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\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).
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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.
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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.
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\26\ PHMSA Gas Distribution Integrity Assessment Question Set,
available at https://www.phmsa.dot.gov/forms/phmsa-gas-distribution-ia-question-set-pdf.
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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.
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\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.
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\28\ 76 FR 5494.
\29\ 74 FR 63905.
\30\ 76 FR 5495.
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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.
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\33\ DOT Form PHMSA F 7100.1-1.
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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.
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\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.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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\
---------------------------------------------------------------------------
\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\
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\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.
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\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.
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\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: http://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