Pipeline Safety: Safety of Underground Natural Gas Storage Facilities, 8104-8127 [2020-00565]

Agencies

• Pipeline and Hazardous Materials Safety Administration
• DEPARTMENT OF TRANSPORTATION

[Federal Register Volume 85, Number 29 (Wednesday, February 12, 2020)]
[Rules and Regulations]
[Pages 8104-8127]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2020-00565]



[[Page 8103]]

Vol. 85

Wednesday,

No. 29

February 12, 2020

Part II





Department of Transportation





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Pipeline and Hazardous Materials Safety Administration





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49 CFR Parts 191, 192, and 195





Pipeline Safety: Safety of Underground Natural Gas Storage Facilities; 
Final Rule

Federal Register / Vol. 85, No. 29 / Wednesday, February 12, 2020 / 
Rules and Regulations

[[Page 8104]]


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DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous Materials Safety Administration

49 CFR Parts 191, 192, and 195

[Docket No. PHMSA-2016-0016; Amdt. Nos. 191-27; 192-126; 195-103]
RIN 2137-AF22


Pipeline Safety: Safety of Underground Natural Gas Storage 
Facilities

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

ACTION: Final rule.

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SUMMARY: The Pipeline and Hazardous Materials Safety Administration is 
publishing this final rule to amend its minimum safety standards for 
underground natural gas storage facilities (UNGSFs). On December 19, 
2016, PHMSA issued an interim final rule (IFR) establishing regulations 
in response to the 2015 Aliso Canyon incident and the subsequent 
mandate in section 12 of the Protecting our Infrastructure of Pipelines 
and Enhancing Safety Act of 2016. The IFR incorporated by reference two 
American Petroleum Institute (API) Recommended Practices (RPs): API RP 
1170, ``Design and Operation of Solution-mined Salt Caverns Used for 
Natural Gas Storage'' (First Edition, July 2015); and API RP 1171, 
``Functional Integrity of Natural Gas Storage in Depleted Hydrocarbon 
Reservoirs and Aquifer Reservoirs'' (First Edition, September 2015). 
The IFR required each provision in the API RPs to apply as mandatory 
(i.e., each ``should'' statement would apply as a ``shall'') unless an 
operator provides written justification for not implementing the 
practice, including an explanation for why it is impracticable and not 
necessary for safety. Based on the comments received to the IFR and a 
petition for reconsideration, PHMSA has determined that the RPs, as 
originally published, will provide PHMSA with a stronger basis upon 
which to base enforcement than the IFR. This final rule also addresses 
recommendations from commenters and a petition for reconsideration of 
the IFR by modifying compliance timelines, revising the definition of a 
UNGSF, clarifying the states' regulatory role, reducing recordkeeping 
and reporting requirements, formalizing integrity management practices, 
and adding risk management requirements for solution-mined salt 
caverns.

DATES: This final rule is effective on March 13, 2020. The Director of 
the Federal Register approved the incorporation by reference on January 
18, 2017.

FOR FURTHER INFORMATION CONTACT: 
    Technical questions: Byron Coy, Senior Technical Advisor, by 
telephone at 609-771-7810 or by email at [email protected].
    General information: Ashlin Bollacker, Technical Writer, by 
telephone at 202-366-4203 or by email at [email protected].

SUPPLEMENTARY INFORMATION: 
I. Executive Summary
    A. Purpose of This Final Rule
    B. Summary of the Major Provisions
    C. Costs and Benefits
II. Background
    A. Overview of Underground Natural Gas Storage
    B. Underground Storage Incidents and Regulatory History
    C. Aliso Canyon Incident
    D. The PIPES Act of 2016
    E. Interagency Task Force
    F. Interim Final Rule
    G. Petition for Reconsideration
III. Comment Summaries and PHMSA's Responses
    A. Introduction
    B. Incorporation by Reference of API Recommended Practices 1170 
and 1171
    C. Compliance Timelines
    D. Placement of Underground Storage Regulations in a New Part 
for Title 49 of the 49 CFR
    E. Suitability of API RPs 1170 and 1171 as the Basis for 
Rulemaking
    F. Integrity Management Practices
    G. Notification Criteria Under 49 CFR Part 191 for Changes at a 
Facility
    H. The States' Role in Regulating UNGSFs
    I. Definitions and Terminology
    J. Requests for Additional or More Stringent Requirements
IV. Regulatory Analyses and Notices

I. Executive Summary

A. Purpose of This Final Rule

    The Pipeline and Hazardous Materials Safety Administration (PHMSA) 
is amending the pipeline safety regulations applicable to underground 
natural gas storage facilities (UNGSFs). PHMSA is amending the UNGSF 
regulations in response to comments and recommendations received on its 
interim final rule (IFR) published on December 19, 2016 (81 FR 91860). 
The IFR implemented PHMSA's authority to regulate UNGSFs and the 
Congressional mandate in section 12 of the PIPES Act (Pub. L. 114-183) 
to establish minimum safety standards for depleted-hydrocarbon 
reservoirs, aquifer reservoirs, and solution-mined salt caverns used 
for the storage of natural gas.\1\ Congress issued the mandate to PHMSA 
following a large-scale natural gas leak at the Aliso Canyon UNGSF in 
Southern California on October 23, 2015. The mandate required PHMSA to 
establish minimum safety standards for UNGSFs within two years of the 
PIPES Act issuance on June 22, 2016. To meet the mandate's deadline--
and address the urgent need for safer storage of natural gas--PHMSA 
published the IFR with a 60-day comment period. The IFR went into 
effect on January 18, 2017.
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    \1\ For a description of these storage types and other basic 
information about underground natural gas storage, see https://www.eia.gov/naturalgas/storage/basics/.
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    Since that time, PHMSA has considered public comments and a 
petition for reconsideration of the IFR and is modifying the minimum 
safety standards for UNGSFs in this final rule accordingly. PHMSA has 
also further reviewed the Final Report of the Interagency Task Force on 
Natural Gas Storage Safety \2\ to ensure any amendments in this final 
rule are consistent with the Task Force's recommendations to PHMSA.\3\ 
As detailed in this final rule, PHMSA believes these changes will 
reduce regulatory burdens and reduce costs for industry and gas 
consumers while sustaining safety and protecting the environment.
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    \2\ ``Ensuring Safe and Reliable Underground Natural Gas 
Storage,'' Final Report of the Interagency Task force on Natural Gas 
Storage Safety; October 2016. See https://www.energy.gov/downloads/report-ensuring-safe-and-reliable-underground-natural-gas-storage.
    \3\ In addition to their comments on the IFR, on March 17, 2017, 
the State of Texas and the Texas Railroad Commission petitioned the 
U.S. Court of Appeals for the Fifth Circuit for review of the IFR 
under 49 U.S.C. 60119(a). See State of Texas v. PHMSA, No. 17-60189 
(5th Cir. Mar. 17, 2017). On April 24, 2017, the court granted INGAA 
and AGA's motions to intervene in the litigation. On July 19, 2017, 
the court granted a joint motion to hold the petition for review in 
abeyance pending the issuance of this final rule.
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B. Summary of the Major Provisions

    Consistent with the IFR, this final rule maintains the 
incorporation by reference of American Petroleum Institute (API) 
Recommended Practices (RPs) 1170 and 1171 (the RPs) as the basis of the 
minimum safety standards in 49 CFR part 192. API RP 1170, ``Design and 
Operation of Solution-mined Salt Caverns Used for Natural Gas Storage'' 
\4\ has recommended practices for solution-mined salt cavern facilities 
used for natural gas storage and covers facility geomechanical 
assessments, cavern well design and drilling, solution mining 
techniques,

[[Page 8105]]

and operations, including monitoring and maintenance practices. API RP 
1171, ``Functional Integrity of Natural Gas Storage in Depleted 
Hydrocarbon Reservoirs and Aquifer Reservoirs'' \5\ has recommended 
practices for natural gas storage in depleted oil and gas reservoirs 
and aquifers, and focuses on storage well, reservoir, and fluid 
management for functional integrity in design, construction, operation, 
monitoring, maintenance, and documentation practices. Both RPs describe 
ways to maintain the functional integrity of design, construction, 
operation, monitoring, maintenance, and documentation practices for 
UNGSFs. The RPs contain numerous provisions that use the term ``shall'' 
to denote a minimum requirement necessary to comply with the RP. The 
RPs also use non-mandatory terms such as ``should,'' ``may,'' and 
``can'' to denote a recommendation that is advised, but not required.
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    \4\ API Recommended Practice 1170 ``Design and Operation of 
Solution-mined Salt Caverns used for Natural Gas Storage (First 
Edition, July 2015).
    \5\ API Recommended Practice 1170 ``Functional Integrity of 
Natural Gas Storage in Depleted Hydrocarbon Reservoirs and Aquifer 
Reservoirs'' (First Edition, September 2015).
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    This final rule amends the IFR in six primary ways. First, PHMSA 
adopts the RPs without modification to the non-mandatory terms. In the 
IFR, PHMSA adopted the RPs by modifying the non-mandatory provisions 
(i.e., statements containing ``should'' and other non-mandatory terms) 
as mandatory requirements (i.e., ``shall''). PHMSA provided that 
operators could deviate from the modified statements by providing a 
justification in their procedure manuals as to why the provision was 
``not practicable and not necessary for safety'' at their specific 
facility. Accordingly, with this final rule, PHMSA also no longer 
requires operators to provide written justifications as to why they 
would not have performed a ``should'' provision.
    Second, this final rule is formalizing requirements and deadlines 
for operators to develop and implement their integrity management (IM) 
programs and to conduct their baseline risk assessments for UNGSFs. As 
noted by commenters and petitioners, the API RPs function as an IM 
system for UNGSFs, which requires more time to implement than the IFR 
allowed. After considering these comments and recommendations, PHMSA is 
relaxing the timeline for completing initial assessments of the 
reservoirs, caverns, and wells. PHMSA discusses these new requirements 
and deadlines in Section III-C, ``Compliance Timelines.''
    Third, this final rule includes a requirement for solution-mined 
salt caverns to follow the same risk management practices as depleted-
hydrocarbon reservoirs and aquifers that apply to the physical 
characteristics and operations of the facility (i.e., follow section 8 
of API RP 1171). Since the publication of the IFR, PHMSA has observed 
that many operators of solution-mined salt caverns are voluntarily 
using section 8 of API RP 1171 to supplement the risk management 
practices in section 10 of API RP 1170. While most salt-cavern UNGSFs 
have a risk-management program in place, section 8 of API RP 1171 
provides more prescriptive practices than API RP 1170 for how an 
operator must develop, implement, and document a program to manage 
risks that could affect the functional integrity of the storage 
operation. Extending the applicability of the recommended practices in 
section 8 of 1171 closes a potential critical safety gap for salt-
cavern storage facilities and may prevent future failures at these 
facilities. PHMSA has codified this practice in the final rule to 
ensure consistency across all UNGSF facilities.
    Fourth, PHMSA is narrowing the scope of reportable events and 
changes at facilities. In addition to annual data reporting and 
National Registry information, the IFR required operators to notify 
PHMSA of certain changes and events and their facilities, such as 
incidents and safety-related conditions. Since the IFR, PHMSA received 
many notifications for routine maintenance activities, which was not 
the intent of the regulation. Operators are not required to notify 
PHMSA of regular maintenance. To make this clear, PHMSA is limiting 
notification of changes to a facility 60 days prior to the following 
events: (1) All plugging or abandonment activities (regardless of 
costs), and (2) construction or maintenance that requires a workover 
rig and costs $200,000 or more. PHMSA is also applying an emergency 
exemption to the 60-day notification requirements, which PHMSA 
overlooked in the IFR.
    Fifth, this final rule is revising the definition of an 
``underground natural gas storage facility.'' The PIPES Act amended 49 
U.S.C. 60101(a) to define an ``underground natural gas storage 
facility'' as ``a gas pipeline facility that stores natural gas in an 
underground facility, including--a depleted hydrocarbon reservoir, an 
aquifer reservoir; or a solution-mined salt cavern reservoir.'' The IFR 
incorporated a modified version of this definition in part 192. Part 
192 covers the transportation of natural gas by pipeline. PHMSA 
discovered through the public comments on the IFR that the placement of 
the definition in part 192 created questions for operators as to where 
a gas pipeline facility ended, and regulations for a UNGSFs began. To 
remedy this confusion, PHMSA is revising the definition of an 
``underground natural gas storage facility'' to exclude other 
components of a gas pipeline or gas pipeline facility covered elsewhere 
in part 192, and eliminate any potential overlap. PHMSA discusses the 
revised definition and the reason for keeping it in part 192 later in 
this document.
    Sixth, PHMSA is changing the name of the reporting portal to the 
``National Registry of Operators'' (formerly the ``National Registry of 
Pipeline and LNG Operators''). Additionally, PHMSA is revising the name 
of the online portal's web address from ``https://opsweb.phmsa.dot.gov'' 
to ``https://portal.phmsa.dot.gov.'' These changes are throughout parts 
191, 192, and 195.

C. Costs and Benefits

    Consistent with Executive Order (E.O.) 12866, PHMSA has prepared a 
Regulatory Impact Analysis (RIA) that includes an assessment of the 
benefits and costs of this final rule, as well as reasonable 
alternatives. PHMSA published an RIA to accompany the IFR as well. This 
final RIA incorporates input from public comments on the IFR and the 
initial RIA. PHMSA has issued the final RIA concurrently with this 
final rule, and it is available in the docket (PHMSA-2016-0016).
    The annualized cost savings for this final rule, relative to the 
IFR, are estimated to be $11 million, applying a 7 percent discount 
rate. The benefits of this final rule come from making permanent the 
safety measures in the IFR and RPs 1170 and 1171, which API and other 
stakeholders developed to prevent leaks and blowouts before they occur. 
The safety measures adopted through the IFR and this final rule will 
prompt operators to undertake or hasten preventive and mitigative 
measures, as well as IM actions, such as mechanical integrity tests, 
that will reduce the probability of releases.
    The IFR reduced the likelihood and magnitude of catastrophic or 
operational natural gas releases by promoting safer practices through 
the incorporation of the recommended practices into the pipeline safety 
regulations. This final rule continues to require these same practices. 
For example, operators are required to assess the mechanical integrity 
of each storage well, evaluate the likelihood of failures at these 
wells, and determine the next steps to remedy conditions that could 
precede the

[[Page 8106]]

failures. Operators are also required to incorporate safety best 
practices when designing and constructing new wells, which could 
further prevent catastrophic failures.
    This final rule also adds a requirement for all solution-mined salt 
caverns to follow the risk management practices in section 8 of RP 
1171. Per the IFR, PHMSA had only required operators of solution-mined 
salt caverns to follow the risk management practices in section 10 of 
RP 1170. The language in section 10, requires operators to take a 
``holistic and comprehensive approach to monitoring cavern integrity,'' 
without providing specifics as to how to implement that approach. Post-
IFR, during preliminary inspections, PHMSA observed operators of 
solution-mined salt caverns applying the framework of the risk 
management practices in section 8 of RP 1171. While RP 1171 applies to 
depleted hydrocarbon reservoirs and aquifer reservoirs, it offers a 
framework for risk management and monitoring that is translatable to 
other types of underground storage facilities. PHMSA expects that other 
operators of solution-mined salt caverns would benefit from a more 
specific framework for implementing the ``holistic and comprehensive 
approach to monitoring cavern integrity'' required in section 10 of 
1170.
    Additionally, codifying the requirement for these operators to 
follow both section 8 of RP 1171 and section 10 of RP 1170 ensures 
consistent safety requirements across all UGS facilities. This change 
may cause those operators who were not already (voluntarily) applying 
API RP 1171 as a framework for monitoring cavern integrity to undertake 
stronger risk management practices, which could ultimately reduce the 
risk of an incident. However, PHMSA considers this action part of the 
baseline requirements to follow a ``holistic and comprehensive approach 
to monitoring cavern integrity'' already prescribed through the IFR. As 
a result, PHMSA does not expect an additional financial burden to 
operators beyond that already in place through the IFR.
    The IFR required operators to provide a written justification for 
each non-mandatory provision of the RPs that they did not perform. This 
final rule removes that recordkeeping burden on operators. Operators 
experience cost savings from the removal of requirements associated 
with deviations from the RPs, including technical reviews by subject 
matter experts and recordkeeping burdens, and reductions in the 
notifications burden.

II. Background

A. Overview of Underground Natural Gas Storage

    Underground storage of natural gas plays a critical role in the 
nation's energy independence and reliability. Notably, having a surplus 
of natural gas provides a buffer from the seasonal variations in supply 
and demand, creating price stability for customers. Over the past ten 
years, natural gas storage has increased 16 percent, prompted, in part, 
by significant growth in domestic shale-gas production.
    There are three principal types of underground natural gas storage 
fields, each with different geological characteristics and capabilities 
that govern their suitability for storage. The three types are depleted 
hydrocarbon reservoirs, aquifer reservoirs, and solution-mined salt 
caverns. Depleted hydrocarbon reservoirs are the most common type of 
storage, representing approximately 80 percent of the total working gas 
capacity in the United States. As the name implies, these facilities 
are repurposed from previous oil or gas production and converted to gas 
storage fields.\6\ Aquifer reservoirs are natural water-bearing 
formations, also converted to gas storage, and represent roughly 9 
percent of the total working gas capacity in the United States. 
Solution-mined salt caverns (salt domes) are geological formations that 
leached out of salt deposits. These facilities represent only about 10 
percent of the total working-gas capacity but provide high withdrawal 
and injection rates relative to their working gas capacity.\7\
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    \6\ Energy Information Administration (EIA). 2015. ``The Basics 
of Underground Natural Gas Storage.'' November 16, 2015. Retrieved 
from https://www.eia.gov/naturalgas/storage/basics/ (Accessed March 
2019).
    \7\ Total working gas capacity percentages do not sum to 100 
percent due to rounding.
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    Of the 403 active UNGSFs in the United States, approximately 60 
percent of the facilities are interstate, and 40 percent of the 
facilities are intrastate.\8\ The total storage capacity at these 
fields was 9,236 billion cubic feet (Bcf), and the total working gas 
capacity was 4,815 Bcf. Facilities identified as interstate represented 
63 percent of total storage capacity and 65 percent of working gas 
capacity.
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    \8\ PHMSA's 2018 annual report data show 403 active underground 
natural gas storage fields in the United States as of 2017, 
distributed across 31 states.
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    Interstate UNGSFs serve interstate facilities, such as providing 
storage for interstate gas transmission pipelines.\9\ These types of 
storage facilities commonly receive surplus gas from interstate 
pipelines during warmer months and then send it back into the product 
stream during colder winter months. Since these UNGSFs serve interstate 
facilities and PHMSA has exclusive pipeline safety jurisdiction over 
the design, construction, operation, and maintenance of interstate gas 
pipeline facilities, the standards in this final rule will affect all 
interstate UNGSFs.
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    \9\ Under 49 U.S.C. 60101(a)(6), an ``interstate gas pipeline 
facility'' (including an interstate UNGSF) is defined as ``a gas 
pipeline facility--(A) used to transport gas; and (B) subject to the 
jurisdiction of the [FERC] under the Natural Gas Act (15 U.S.C. 717 
et seq.).'' The term ``transporting gas'' is defined in Sec.  
60101(a)(21) as ``the gathering, transmission, or distribution of 
gas by pipeline, or the storage of gas, in interstate or foreign 
commerce . . .''
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    Intrastate UNGSFs, on the other hand, are facilities that provide 
gas storage for intrastate pipelines, most notably local gas 
distribution companies (LDCs). These storage facilities serve 
intrastate pipelines that are contained entirely within a particular 
State and that do not fall within the jurisdiction of the Federal 
Energy Regulatory Commission (FERC). As discussed more fully below, 
these intrastate ``gas pipeline facilities'' are generally subject to 
the IFR and this final rule. Intrastate UNGSFs may continue to also be 
subject to State regulations provided that: (a) The otherwise 
applicable State regulation does not conflict with the Federal minimum 
safety standards established in the final rule, and (b) the applicable 
State authority has filed a certification with PHMSA to participate as 
a full State partner under the new Federal program and to receive 
Federal funding through PHMSA.

B. Underground Storage Incidents and Regulatory History

    While rare, serious incidents at underground storage facilities 
have occurred. For instance, on April 7, 1992, an uncontrolled release 
of highly volatile liquids from a salt-dome storage cavern near 
Brenham, Texas, formed a heavier-than-air gas cloud that exploded. 
Three people died in the accident, with an additional 21 people treated 
for injuries at area hospitals. Property damage from the accident 
exceeded $9 million.
    Following its accident investigation, the National Transportation 
Safety Board (NTSB) published pipeline safety recommendation No. P-93-9 
regarding underground storage. Recommendation P-93-9 asked PHMSA's 
predecessor agency, the Research and Special Programs Administration 
(RSPA), to develop safety requirements for storage of highly volatile 
liquids and natural gas

[[Page 8107]]

in underground facilities, including a requirement that all pipeline 
operators perform safety analyses of new and existing underground 
geologic storage systems to identify potential failures, determine the 
likelihood that each failure will occur, and assess the feasibility of 
reducing the risk.\10\
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    \10\ National Transportation Safety Board, Pipeline Accident 
Report PAR-93/01 (Nov. 4, 1993).
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    In response to the NTSB's safety recommendation, RSPA held a public 
meeting \11\ to determine what actions it should take, if any, 
regarding the regulation of underground storage of natural gas and 
hazardous liquids. The participants expressed mixed views on whether 
RSPA should begin to regulate ``downhole'' pipe and underground 
storage. Most participants spoke favorably of industry safety practices 
and State regulation but saw no immediate need for Federal regulatory 
action.
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    \11\ (Docket PS-137, 59 FR 30567, June 14, 1994).
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    On July 1, 1997, RPSA issued an advisory bulletin (ADB-97-04) to 
inform UNGSF owners and operators of the availability of guidelines for 
the design and operation of underground storage facilities. 
Specifically, the advisory bulletin pointed to the safety standards 
guide from the Interstate Oil and Gas Compact Commission (IOGCC) \12\ 
and API as appropriate for use by pipeline operators and State 
regulatory agencies. The IOGCC guide provided safety standards for the 
design, construction, and operation of gas storage caverns. API had 
published guidelines for the underground storage of liquid 
hydrocarbons. RP 1114, ``Design of Solution-Mined Underground Storage 
Facilities,'' June 1994, provided basic guidance on the design and 
development of new solution-mined underground storage facilities. RP 
1115, ``Operation of Solution-Mined Underground Storage Facilities,'' 
September 1994, provided guidance on the operation of solution-mined 
underground hydrocarbon liquid or liquefied petroleum gas storage 
facilities.
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    \12\ Interstate Oil and Gas Compact Commission, ``Natural Gas 
Storage in Salt Caverns: A Guide for State Regulators.'' (IOGCC 
Guide), 1995.
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    Another catastrophic natural gas leak happened in January 2001 
after a wellbore failed at the Yaggy storage field near Hutchinson, 
Kansas. The natural gas migrated nine miles underground, where it 
eventually surfaced through abandoned wells. Once at the surface, the 
natural gas exploded, killing two people and destroying two 
businesses.\13\ After a month, the flares burned off, with the ultimate 
loss of 143 million cubic feet (MCF) of natural gas from the storage 
field.
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    \13\ Allison, M. Lee, 2001, The Hutchinson Gas Explosions: 
Unraveling a Geologic Mystery, Kansas Bar Association, 26th Annual 
KBA/KIOGA Oil and Gas Law Conference, v1, p3-1 to 3-29.
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    These incidents at UNGSFs alerted operators and regulators to 
consider assessing the safety of these facilities. By 2012, API had 
begun developing additional guidance for the safety of UNGSFs. API 
developed RP 1170 and 1171 over several years, based on input from many 
industry stakeholders, including regulators such as PHMSA, FERC, and 
five State regulatory agencies, as well as the API Midstream Group. In 
July 2015, API issued RP 1170, ``Design and Operation of Solution-mined 
Salt Caverns Used for Natural Gas Storage.'' API RP 1170 provides 
recommendations and requirements for geo-mechanical assessments, cavern 
well design and drilling, solution mining techniques, operations and 
maintenance procedures, and practices for salt caverns. In September 
2015, API issued RP 1171, ``Functional Integrity of Natural Gas Storage 
in Depleted Hydrocarbon Reservoirs and Aquifer Reservoirs,'' which 
focuses on storage well, reservoir, and fluid management for functional 
integrity in design, construction, operations and maintenance 
procedures, monitoring, and documentation practices. The RPs 
appropriately recognize the variety and diversity of UNGSFs used 
throughout the United States and are not limited to addressing 
facilities in a single State, basin, geological setting, or well type.

C. Aliso Canyon Incident

    Shortly after the publication of the industry safety standards RP 
1170 and RP 1171, another major UNGSF incident occurred. On October 23, 
2015, Southern California Gas Company (SoCalGas) discovered a leak that 
manifested into the largest methane leak from a natural gas storage 
facility in U.S. history. Well SS-25 in the Aliso Canyon storage field, 
located in Los Angeles County, California, leaked for nearly four 
months until it was permanently sealed on February 17, 2016. While 
SoCalGas attempted to plug the leak, residents in nearby neighborhoods 
experienced health symptoms consistent with exposure to the odorants 
(mercaptans) added to natural gas and residual components from previous 
oil production in the field. The incident temporarily displaced more 
than 5,000 households from their homes, according to the Aliso Canyon 
Incident Command briefing report issued on February 1, 2016, although 
some sources place the number of related households at approximately 
8,000.\14\
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    \14\ For example, see KPCC news report on August 4, 2016, ``Cost 
estimate of Aliso Canyon gas leak hits $717 million''. https://www.scpr.org/news/2016/08/04/63268/cost-estimate-of-aliso-canyon-gas-leak-hits-717-mi/.
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    The leak at Aliso Canyon ultimately released approximately 5.7 Bcf 
of natural gas into the atmosphere, translating to 109,000 metric tons 
\15\ of methane, a potent greenhouse gas, as well as numerous other 
pollutants.\16\ Additional reports identified other potential health 
effects that lasted even after the well was sealed. A report by the Los 
Angeles County of Public Health suggests that the continued health 
symptoms may be due to contaminants in indoor air and dust.\17\ As of 
December 31, 2016, SoCalGas and its parent company, Sempra Energy, 
recorded estimated costs of $913 million to control the release, 
monitor air emissions, relocate residents, and cover legal and other 
expenses.\18\ The singular well that failed in the Aliso Canyon 
accident (SS-25) had originally been drilled in 1953 and was re-
purposed for natural gas storage in 1972. The age of this well is not 
unusual. Per data from the American Gas Association (AGA), 
approximately 60 percent of active storage wells are located in fields 
that were activated before 1960.
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    \15\ CARB estimates that the incident resulted in a total 
emission of 99,650  9,300 metric tons of methane (CARB, 
2016a) and seeks mitigation of 109,000 metric tons.
    \16\ California Air Resources Board (CARB), 2016; County of Los 
Angeles Public Health.
    \17\ Ibid. CARB.
    \18\ Of the $913 million of costs, approximately 60 percent is 
for the temporary relocation program (including cleaning costs and 
certain labor costs). Other estimated costs include amounts for 
efforts to control the well, stop the Leak, stop or reduce the 
emissions, and the estimated cost of the root cause analysis being 
conducted by an independent third party to investigate the cause of 
the Leak. The remaining portion of the $913 million includes legal 
costs incurred to defend litigation, the value of lost gas, the 
costs to mitigate the actual natural gas released, the estimated 
costs to settle certain actions and other costs. The value of lost 
gas reflects the replacement cost of volumes purchased through 
December 2017 and estimates for purchases in 2018. As of mid-January 
2018, SoCalGas has replaced all lost gas. SoCalGas adjusts its 
estimated total liability associated with the Leak as additional 
information becomes available.'' (SoCalGas/Sempra, 2018).
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    The Aliso Canyon incident created serious energy-supply challenges 
for the region and prompted public concerns about the safety of UNGSFs, 
including the extent and effectiveness of Federal and State oversight. 
On February 5, 2016, PHMSA issued an advisory bulletin (ABD-2016-02), 
identifying specific minimum actions that operators of UNGSFs should 
take, in addition to the recommendations of ADB-97-04,

[[Page 8108]]

API RP 1170, API RP 1171, and the IOGCC Guide. The 2016 advisory 
bulletin recommended that operators begin reviewing their operating, 
maintenance, and emergency response activities and apply the new RPs 
accordingly.
    On July 14, 2016, PHMSA held a public meeting to discuss 
potentially extending its regulations to include transportation-related 
UNGSFs. PHMSA heard from a diverse group of stakeholders, including 
State regulators, emergency responders, and residents, including those 
impacted by the Aliso Canyon incident. PHMSA concluded that it should 
take action to incorporate by reference API RP 1170 and API RP 1171 
into part 192. The RPs describe a range of measures that UNGSF 
operators should undertake to ensure the safe operations of their 
facilities. The RPs also include construction, maintenance, IM, 
security, and emergency response procedures.

D. The PIPES Act of 2016

    The Aliso Canyon incident prompted broader public concerns as to 
how to prevent similar UNGSF accidents in the future. Congress 
addressed these concerns in two sections of the PIPES Act, enacted on 
June 22, 2016 (Pub. L. 114-183). Section 12 of the PIPES Act required 
PHMSA to issue minimum safety standards for all UNGSFs within two years 
of enactment. The statute defines an ``underground natural gas storage 
facility'' as a ``gas pipeline facility that stores natural gas in an 
underground facility.'' Because title 49 United States Code (U.S.C.) 
60101(a) already defines ``gas pipeline facility'' as ``a pipeline, a 
right of way, a facility, a building, or equipment used in transporting 
gas or treating gas during its transportation,'' PHMSA interprets the 
PIPES Act as directing it to regulate only those UNGSFs that store 
natural gas incidental to transportation.
    The PIPES Act requires that in issuing minimum safety standards for 
UNGSFs, PHMSA must: (1) Consider consensus standards for the operation, 
environmental protection, and integrity management of underground 
natural gas storage facilities; (2) consider the economic impacts of 
the regulations on individual gas customers; (3) ensure that the 
regulations do not have a significant economic impact on end users; and 
(4) consider the recommendations of the Aliso Canyon natural gas leak 
task force established under section 31 of the PIPES Act of 2016.
    The Secretary of Transportation (the Secretary) delegated this 
responsibility under chapter 601 of title 49 U.S.C. to the PHMSA 
Administrator (49 CFR 1.97). PHMSA fulfilled this mandate by publishing 
the IFR on December 19, 2016. The PIPES Act provides that states may 
adopt additional or more stringent safety standards for intrastate 
UNGSFs if such standards are compatible with these Federal regulations.

E. Interagency Task Force

    In addition to section 12 of the PIPES Act, Congress included a 
second mandate, section 31, directing the Department of Energy (DOE) to 
establish an Interagency Task Force on Natural Gas Storage Safety to 
perform an analysis of the Aliso Canyon events and make recommendations 
to reduce the occurrence of similar events in the future. PHMSA and DOE 
co-led the effort. The Task Force established several working groups, 
comprised of premier scientists, engineers, and technical experts from 
the Executive Office of the President and various Federal agencies. The 
working groups examined three key areas:
     The integrity of natural gas wells at storage facilities;
     The public health and environmental effects from natural 
gas leaks; and
     The nation's vulnerability to reduced energy reliability 
in the event of future leaks.
    In October 2016, the Task Force issued its final report on natural 
gas storage safety and made 44 recommendations to operators and 
regulators. The main recommendation to PHMSA was to incorporate 
existing industry consensus standards, API RP 1170 and 1171, into part 
192 of the regulations in an enforceable manner, and consider 
supplementing the regulations with recordkeeping and reporting 
requirements as necessary. The Task Force recommended that operators 
develop comprehensive risk-management plans that addressed risks based 
on their potential severity and probability of occurrence. These plans 
should document an operator's risk-management strategy, identify risks, 
define responsibilities among stakeholders, assess risks, and take 
appropriate action to reduce risks to well integrity.
    The Task Force's report also highlighted growing concerns regarding 
the age of the nation's natural gas storage infrastructure. For 
example, wells reflect material, technology, and design factors that 
may have been appropriate at the time they were constructed, but may 
not meet design criteria for wells drilled today. Over time, corrosion, 
other environmental processes, and mechanical stresses from the 
injection and withdrawal of natural gas can impact well integrity. 
Wells in depleted oil fields may have been designed for lower operating 
pressures than what they may be subject to now. Many of these wells 
were designed without redundant barriers to reduce the risk of gas 
migration. One of the lessons from the Aliso Canyon incident is that 
wells without redundant barriers present higher risks because they have 
a single point of possible failure that may be extremely difficult to 
shut off or kill.

F. Interim Final Rule

    On December 19, 2016, PHMSA issued the IFR that satisfied section 
12 of the PIPES Act, exercising the agency's statutory authority to 
regulate underground natural gas storage facilities. The IFR amended 
the pipeline safety regulations found at 49 CFR parts 191 and 192, to 
address critical safety issues related to ``downhole'' UNGSF 
facilities, including wells, wellbore tubing, casing, and wellheads (81 
FR 91860). Additionally, the IFR added a definition of ``underground 
natural gas storage facility'' to Sec. Sec.  191.3 and 192.12 and 
applied reporting requirements to operators of UNGSFs similar to those 
applicable to operators of other gas pipeline facilities, including 
annual reports, incident reports, reports of major construction and 
organizational changes, and registration with the National Operator 
Registry.
    Effective January 18, 2017, all UNGSFs, both intrastate and 
interstate, now had to meet the minimum standards outlined in RPs 1170 
and 1171 and were subject to inspection by PHMSA or a PHMSA-certified 
State entity. The IFR made each provision in the RPs 1170 and 1171 
mandatory unless the operator documented a technical justification why 
compliance with a provision was not practicable and not necessary for 
safety. Operators were required to incorporate the RPs into their 
written operations, maintenance, and emergency response program manuals 
following Sec.  192.605. PHMSA, or a certified State partner, would 
review any of the operators' justifications and its procedure manuals 
during compliance inspections.
    After publishing the IFR, PHMSA took significant steps to educate 
the regulated community on the new requirements, to promote a better 
understanding of issues concerning integrity assessments of UNGSFs and 
the implementation of the RPs. The first action was to publish 
frequently asked

[[Page 8109]]

questions (FAQs).\19\ The FAQs provided guidance on the procedures, 
implementation plans, and schedules that operators should have in place 
to meet the requirements in the applicable RPs. For example, while the 
IFR did not provide clear timelines for operators to complete the 
integrity assessments required by the RPs, the FAQs provided a 
recommended implementation schedule. With the issuance of this final 
rule, PHMSA will revise the FAQ guidance material to reflect these 
regulations as amended.
---------------------------------------------------------------------------

    \19\ ``Underground Natural Gas Storage: FAQs.'' (revised April 
2017) https://primis.phmsa.dot.gov/ung/faqs.htm.
---------------------------------------------------------------------------

    In preparation for the development of inspection and enforcement 
efforts, PHMSA subject matter experts conducted preliminary site 
assessments at a cross-section of UNGSFs from May to July of 2017.
    Additionally, PHMSA has instituted a program for training Federal 
and State inspectors on the new minimum Federal standards affecting all 
UNGSF facilities. As it promulgates this final rule, PHMSA is prepared 
to modify the program through future regulations and guidance to keep 
pace with evolving consensus safety standards, academic research, and 
lessons learned from the firsthand experience of its inspectors, State 
regulators, affected stakeholders, and the public.

G. Petition for Reconsideration

    On January 18, 2017, the American Gas Association (AGA), American 
Petroleum Institute (API), American Public Gas Association (APGA), and 
Interstate Natural Gas Association of America (INGAA) (the 
``Associations'') jointly filed a petition for reconsideration of the 
IFR. AGA represents local energy companies, as well as residential, 
commercial, and industrial natural gas customers. API is a national 
trade association representing the oil and natural gas industry, 
including gas pipelines and UNGSF operators. APGA is a national, non-
profit association of publicly-owned natural gas distribution systems. 
INGAA is an industry trade association representing interstate natural 
gas pipeline companies in the United States.\20\
---------------------------------------------------------------------------

    \20\ On April 17, 2017, INGAA withdrew from the petition for 
reconsideration, but the other three Associations have remained as 
petitioners.
---------------------------------------------------------------------------

    In the petition, the Associations affirmed their support for 
PHMSA's efforts to regulate the safety of UNGSFs. They reminded PHMSA 
that the Associations and their members had supported PHMSA's 
incorporation by reference of the RPs as Federal standards for natural 
gas storage. They stressed the importance of adopting the RPs to 
advance the safety of the pipeline transportation system but asked 
PHMSA to revise the IFR to incorporate RP 1170 and API RP 1171 without 
modification and to provide for reasonable implementation periods. The 
Associations stated that the changes requested in the petition would 
ensure that PHMSA's regulations would be practical, reasonable, and 
effective.
    On June 20, 2017, PHMSA issued a notice stating that it would 
provide an answer to the petition in the final rule (82 FR 28224). 
PHMSA announced that in the interim, it would not issue any enforcement 
citations for failure to meet any of the non-mandatory provisions of 
the RPs that the IFR converted to mandatory ones until one year after 
the issuance the final rule. PHMSA has considered the recommendations 
from the Associations and is answering their petition in this final 
rule.

III. Comment Summaries and PHMSA's Responses

A. Introduction

    PHMSA received 82 comments and one petition for reconsideration in 
response to the IFR issued on December 19, 2016. PHMSA provided a 60-
day comment period initially but re-opened it on October 19, 2017 (82 
FR 48655), for an additional 30 days to provide all interested parties 
with the opportunity to comment on the IFR and the merits and claims of 
the petition for reconsideration. During the initial 60-day comment 
period, PHMSA received 28 comments. PHMSA received 54 additional 
comments during the re-opened 30-day comment period, but only 14 of 
those 54 related to this rulemaking.\21\ Half of those 14 comments were 
from organizations that had already submitted comments during the 
initial, 60-day comment period.
---------------------------------------------------------------------------

    \21\ The 40 comments that PHMSA deemed not relevant appear to 
have been submitted anonymously using automated technology (i.e., 
bots). While these comments raise generalized issues related to 
environmental protection (climate change, renewable/alternative 
energy, streamlining environmental reviews, etc.), the comments do 
not connect their generalized statements to any of the specific 
provisions of this rulemaking, such that they would become 
meaningful to the issue of the safety of underground natural gas 
storage systems.
---------------------------------------------------------------------------

    PHMSA discusses and responds to these comments and recommendations 
in sections B through J, below. For organizational purposes, PHMSA has 
grouped comments by subject matter. Below is a list of entities who 
submitted comments on the IFR.

 Atmos Energy
 Consumers Energy
 Dow Chemical Company (Dow)
 ENSTOR
 Environmental Defense Fund (EDF)
 Gas Free Seneca
 Gas Piping Technology Committee (GPTC)
 Geological Maps Foundation
 GPA Midstream Association (GPA)
 Hilcorp Alaska
 Hon. Brad Sherman, representing 30th Congressional District of 
California
 Independent Petroleum Association of America (IPAA)
 Joint Comment from American Gas Association (AGA), the 
American Petroleum Institute (API), the American Public Gas Association 
(APGA), and the Interstate Natural Gas Association of America (INGAA)
 Joint Comment from the States First Initiative, the Interstate 
Oil and Gas Compact Commission (IOGCC), and Groundwater Protection 
Council (GWPC)
 Louisiana Mid-Continent Oil and Gas Association (LMOGA)
 Michigan Department of Environmental Quality
 New York State Department of Environmental Conservation
 Northern Natural Gas
 Pacific Gas and Electric Company (PG&E)
 Private Citizens (50)
 Railroad Commission of Texas
 Southern California Gas Company (SoCalGas)
 Texas Pipeline Association
 TransCanada
 Vectren

B. Incorporation by Reference of API Recommended Practices 1170 and 
1171

    In the IFR, PHMSA required operators to treat non-mandatory 
language in the RPs as mandatory. For each provision modified by the 
IFR, an operator could deviate from the recommended practice by 
providing in its procedures manual a technical justification for each 
deviation. Under the IFR, PHMSA required an operator to use a subject 
matter expert to review and document the technical justification, and a 
member of the operator's executive leadership was required to review, 
approve, and document the date of approval. During routine inspections, 
PHMSA would review an operator's justifications for deviating from the 
modified provisions.
1. Comments on PHMSA's Modification of the RPs
    Many commenters disagreed with PHMSA's modification of the non-
mandatory provisions of the RPs. Almost all commenters supported the 
Associations' position concerning the

[[Page 8110]]

conversion of the non-mandatory provisions in RPs 1170 and 1171 to 
mandatory. Generally, commenters supported the need for consistent 
minimum safety standards for all UNGSFs and supported regulations to 
that effect. Those same commenters asserted that if PHMSA adopted the 
IFR without modification, it would impose burdensome and impracticable 
requirements on operators.
    In their petition, the Associations stated that ``changing the 
[RPs] in this manner is not necessary for enforcement, nor is it 
practicable or reasonable.'' The Associations stated their belief that 
there was ``no regulatory justification for making all `non-mandatory' 
provisions `mandatory,' '' and requested that PHMSA eliminate this 
provision. Further, the Associations said that although the RPs use 
both non-mandatory and mandatory language, this alone does not affect 
their enforceability. They said that the RPs contain enough mandatory 
provisions to ensure enforceability. The Associations used the 
mandatory provisions in section 8 to demonstrate that the RPs are broad 
enough, as written, to be enforced. Additionally, they stated that the 
non-mandatory statements in the RPs do not compromise the 
enforceability of the broad requirements imposed on operators through 
the mandatory provisions.
    The Texas RRC stated that it strongly disagreed with PHMSA's 
modification of the RPs. The Texas RRC noted that the wholesale 
adoption of RPs would lead to confusion and have unintended 
consequences. It said that if PHMSA kept the modification to the non-
mandatory provisions in the final rule, it would undermine the 
integrity of the original RPs, ultimately making them even more 
difficult to enforce. Lastly, the Texas RRC stated that, while the IFR 
allowed an operator to deviate from particular provisions, PHMSA did 
not provide a process or timeframe by which the agency would review, 
approve, or deny the operator's alternative procedure(s). The Texas RRC 
requested that, if PHMSA chose to incorporate the RPs as modified by 
the IFR, the agency should add a review process and timeline for 
consideration of requests for deviation from the modified provisions.
    ENSTOR Operating Company, LLC (ENSTOR), asserted that converting 
all non-mandatory provisions in the RPs to mandatory requirements would 
undermine the risk-based approach of the RPs and create unintended 
results. ENSTOR stated that PHMSA's conversion of non-mandatory RP 
statements in sections 8, 9, 10, and 11 of RP 1171 to mandatory 
provisions could establish statutorily-impermissible retroactive 
requirements, such as requiring the use of observation wells drilled 
around, above, and below a reservoir. ENSTOR added that PHMSA ``can 
simply require operators to discontinue any deviations that the agency 
does not agree with,'' and ``there are no standards to guide the 
agency's determination and no means for review or appeal of a denial of 
an operator deviation.''
    Some operators stated that the process for justifying deviations 
from a specific non-mandatory RP would be time-intensive, expensive, 
and unworkable for many operators. LMOGA stated that requiring 
technical documentation for each deviation was excessive since the RPs 
themselves already identified the non-mandatory practices as applicable 
on a case-by-case and site-specific basis. Further, LMOGA noted that 
the IFR required each deviation must be ``technically reviewed and 
documented by a subject matter expert to ensure that there will be no 
adverse impact on the facility. . . .'' LMOGA argued that the term 
``subject matter expert'' was vague and imprecise.
    EDF said that PHMSA would not be reviewing an operator's technical 
justifications until after the operator had already deviated from a 
recommended practice and contended that this could allow harmful 
activities to persist until an inspection took place at the facility. 
Further, EDF said that operators might make significant financial 
commitments in reliance on unapproved deviations, only to see their 
decisions overturned after the fact, without practical recourse, by 
PHMSA. Regarding the IFR's treatment of non-mandatory provisions as 
mandatory, EDF stated its preference would be for PHMSA to adopt the 
API RPs but examine the non-mandatory provisions of the API RPs on a 
provision-by-provision basis to determine if any should be made 
mandatory, and adopt additional regulatory requirements to fill in 
potential gaps in the final rule.
    TransCanada, which participated in the development of RP 1171, 
stated that the inclusion of both ``should'' and ``shall'' in the RPs 
reflected a deliberate, iterative, consensus-building effort that 
resulted in the selection of those specific words. TransCanada went on 
to say that it would not be prudent to make such recommendations 
mandatory because doing so could lead to a misplaced effort to document 
exceptions when operators should be focusing on the imperatives of IM 
and the development of effective procedures.
2. PHMSA's Response to Comments on Its Modification of the API RPs 1170 
and 1171
    After considering the petition for reconsideration and public 
comments, PHMSA is accepting the recommendation to adopt the RPs 1170 
and 1171 as originally written by API, without modification. When 
drafting the IFR, PHMSA needed to provide an immediate and reasonable 
means by which it could begin regulating UNGSFs, while, at the same 
time, implementing sections 12 and 31 of the PIPES Act. As discussed 
earlier, section 12 of the PIPES Act required PHMSA to consider 
existing industry standards and recommendations from the Interagency 
Task Force (created by section 31) as the basis for its pending 
regulations. In its 2016 report, the Interagency Task Force recommended 
that PHMSA consider ``incorporating existing industry-recommended 
practices API RP 1170 and 1171 into the part 192 regulations, and they 
should be adopted in a manner that can be enforced.'' Historically, 
PHMSA has successfully incorporated by reference many industry 
standards, guidance, and recommended practices in lieu of developing 
its own regulations.
    After additional review, PHMSA has determined that adopting the RPs 
as originally published by API would still provide significant benefits 
for safety, the environment, and public health but would be much easier 
for the regulated industry and the public to understand and for PHMSA 
to interpret and enforce. The non-mandatory provisions in the RP 
provide operators with guidance for optional considerations based on 
the features and characteristics of individual storage facilities. 
However, the RPs still require all operators to develop policies and 
procedures to ensure the functional integrity of UNGSFs and to inspect 
and verify the operational integrity of these facilities on a site-
specific basis and will provide PHMSA with a stronger basis upon which 
to base enforcement than the IFR.
    As the Associations pointed out in their petition for 
reconsideration, the existence of ``non-mandatory provisions in the RPs 
does not affect their overall enforceability.'' Throughout the RPs, 
there are many broad mandatory provisions that operators of UNGSFs must 
implement, using a range of options considered in accompanying non-
mandatory provisions. The non-mandatory provisions provide operators 
with illustrations, examples, or choices of action for how to achieve 
compliance with the mandatory provisions. Because these non-mandatory 
provisions are

[[Page 8111]]

closely tied to the mandatory provisions that operators must meet, any 
non-mandatory provision remains enforceable to the extent that it is 
necessary, in the context of a particular operator or facility, to 
ensure compliance with a mandatory provision in the Recommended 
Practice.
    Based on the petition for reconsideration, the post-IFR comments 
received, as well as its experience with the application and 
enforcement of similar consensus standards and recommended practices, 
PHMSA believes that adopting the RPs in their original published form, 
will accomplish the goal of the IFR, which was to improve safety. The 
means of achieving this goal was to establish, for the first time, 
minimum Federal safety standards that would require operators of all 
UNGSFs to meet certain basic, uniform, and risk-based policies and 
procedures as outlined in the RPs. In evaluating regulatory 
alternatives, PHMSA did consider adopting a portion of the ``should'' 
provisions to identify and address any potential gaps, but PHMSA 
ultimately decided not to because the Agency does not have sufficient 
information to identify whether there are ``should'' statements that 
are, on average, more or less practical and necessary at each site, and 
thus would be more or less likely to cause operators to seek 
deviations. In light of this factor and the comments received, PHMSA is 
convinced that treating the non-mandatory provision as written in the 
RPs is the better course of action because it adds clarity to the 
provisions which should help improve compliance while providing at 
least an equivalent level of safety as the IFR.
    The IFR and this final rule are PHMSA's first effort to establish a 
national regulatory program for UNGSFs. This program includes features 
such as basic reporting requirements, Federal and State inspections, 
and a Federal-State partnership that will enable States to go beyond 
the RPs by adding additional or more stringent requirements. As the 
agency and the industry gain experience implementing this new 
regulatory program, they will learn what improvements need to be made. 
If experience shows that the RPs do not provide an adequate level of 
safety for certain activities or risks, PHMSA will consider the need to 
modify the regulations, as appropriate.

C. Compliance Timelines

    The IFR required that UNGSFs constructed before July 18, 2017, meet 
all operations, maintenance, integrity demonstration and verification, 
monitoring, threat and hazard identification, assessment, remediation, 
site security, emergency response and preparedness, and recordkeeping 
provisions of the applicable RPs within one year from the effective 
date of the IFR, i.e., January 18, 2018. Specifically, existing UNGSFs 
using a solution-mined salt cavern for storage were required to meet 
the requirements of RP 1170, sections 9, 10, and 11, and operators of 
existing UNGSFs using a depleted hydrocarbon reservoir or an aquifer 
reservoir for gas storage were required to meet the requirements of RP 
1171, sections 8, 9, 10, and 11, by the same date.
    Following the publication of the IFR on December 19, 2016, PHMSA 
published FAQ guidance (April 2017) to assist operators in applying the 
RPs. The FAQs included a suggested timeline for operators to complete 
the risk analysis and baseline assessments for the requirements in the 
IFR.
1. Comments on the Compliance Timelines
    PHMSA gave operators one year from the effective date of the IFR to 
comply with the IFR. Commenters stated that the timeline for compliance 
provided in the IFR was unreasonable, and PHMSA's expectations for 
operators were unclear. Commenters requested that the final rule adopt 
phased-in compliance timelines, as PHMSA has done in previous 
rulemakings. Most commenters recommended that PHMSA follow the 
timelines published in its Underground Natural Gas Storage FAQs (April 
2017).
    Most industry commenters asked that PHMSA modify the compliance 
timelines to break it up into phases and extend the overall schedule, 
similar to what the FAQs outlined, which suggested that operators 
complete the baseline integrity assessments of each storage field 
within three to eight years. These commenters agreed that the FAQ's 
timelines for baseline integrity assessments were realistic and that 
any shorter timeframe was unrealistic and impracticable. They supported 
including clear, phased-in timelines in the final rule. Most said it 
would take longer than 12 months to implement all aspects of the RPs 
fully and that the PHMSA should extend the compliance deadline.
    The Associations requested that the final rule incorporate the risk 
assessment and integrity-management timelines currently outlined in the 
FAQs.\22\ The Associations doubted that PHMSA had intended to require 
operators to implement all actions under the applicable sections of the 
RPs within one year. In their comment, the Associations spoke of an 
operator that had recently implemented the RPs at its facility. The 
operator reported that it took over 18 months to gather the subject 
matter experts and complete the integrity plans and operating 
procedures. The Associations added that operators should expedite the 
implementation of preventive and mitigative measures for high-risk or 
imminent-risk facilities, as identified by their risk assessments.
---------------------------------------------------------------------------

    \22\ ``Underground Natural Gas Storage FAQs,'' issued by PHMSA 
in April 2017.
---------------------------------------------------------------------------

    Similarly, TransCanada stated that it was impractical to implement 
the IFR by January 18, 2018, and asked that PHMSA clarify in the final 
rule what the agency expected operators to have achieved by January 18, 
2018, and beyond. TransCanada agreed, with certain reservations, that 
baseline risk assessments could begin within one to two years of the 
effective date of the final rule. They also agreed that three to eight 
years was enough time to complete risk assessments for all individual 
wells at UNGSFs.
2. Response to Comments on the Compliance Timelines
    PHMSA is accepting the commenters' recommendations to reconsider 
the compliance timelines in the final rule. These timelines are similar 
to the ones published PHMSA's Underground Natural Gas Storage FAQs 
(April 2017). Below is a summary of the compliance timelines for 
implementing a UNGSF program.
Deadline for Written Procedures
    Consistent with the IFR, operators must prepare and follow written 
procedures for the operations, maintenance, and emergency management 
and response activities outlined by the applicable RPs. However, this 
final rule removes the requirement in the IFR that these procedures be 
incorporated into an operator's existing procedural manuals required 
for gas pipelines under Sec.  192.605. Instead, the final rule replaces 
this provision with a similar requirement that UNGSF operators develop 
written procedures for carrying out the final rule and maintain and 
update them in a similar fashion as required by Sec.  192.605 for gas 
pipelines. In the final rule, the new requirement is in a new paragraph 
exclusive to UNGSFs under Sec.  192.12.
    Accordingly, operators must establish and follow written procedures 
for implementing their UNGSF programs. By January 18, 2018, all 
operators with

[[Page 8112]]

facilities constructed on or before July 18, 2017, must have 
established and put into service procedures for operations, 
maintenance, and emergency preparedness. All other operators must have 
these procedures in place prior to commencing operations. Operators 
must also establish an interval for reviewing and updating these 
written procedure manuals, not exceeding 15 months, but at least once 
each calendar year.
Integrity Management Framework
    By January 18, 2018, all operators with facilities constructed on 
or before July 18, 2017, must have established a framework for IM under 
the IFR. All other operators must have this framework in place prior to 
commencing operations. An initial framework means a written explanation 
of the mechanisms or procedures the operator will use to implement each 
program and API RP to ensure compliance with this final rule. These 
procedures, implementation framework, and schedules do not need to be 
fully fleshed out but must be sufficient for putting the program in 
place over the long term. PHMSA expects that each operator's 
implementation framework and schedules will evolve into a more 
detailed, comprehensive, and robust program as the operator's program 
matures. An operator must make continual improvements to the program.
    The IM framework for a UNGSF must include:
     A plan for developing and implementing each program 
element;
     An outline of the procedures to be developed;
     The roles and responsibilities of UNGSF staff assigned to 
develop and implement the procedures;
     A plan for how staff will be trained in awareness and 
application of the procedures;
     Timelines for implementing each program element, including 
the risk analysis and baseline risk assessments; and
     A plan for how to incorporate information gained from 
experience into the IM program on a continuous basis.
Timelines for Conducting Risk Assessments
    By four years after the effective date of this final rule, each 
operator must have completed baseline risk assessments for 40 percent 
of all its wellbores, wellheads, and associated components. Operators 
should generally prioritize assessments on higher-risk wells first, 
based on a matrix of identified threats, hazards, and the likelihood of 
their occurrence. Operators must complete baseline assessments of all 
reservoirs and caverns by the same date. By seven years after the 
effective date of this final rule, operators must have completed 
baseline risk assessments for all remaining wellbores, wellheads, and 
associated components. This implementation period is similar to the one 
published in PHMSA's Underground Natural Gas Storage FAQs (revised 
April 2017).\23\
---------------------------------------------------------------------------

    \23\ https://primis.phmsa.dot.gov/ung/faqs.htm.
---------------------------------------------------------------------------

D. Placement of Underground Storage Regulations in a New Part for Title 
49 of the 49 CFR

    The IFR added requirements in parts 191 and 192 for UNGSFs that 
cover reporting, recordkeeping, design, construction, and operation and 
maintenance procedures and practices. Before the IFR, there were no 
Federal regulations pertaining directly to UNGSFs. While part 192 
already covered much of the surface piping at these facilities, up to 
the wing-valve assemblies on the wellhead at UNGSFs served by pipeline, 
PHMSA had not previously issued rules for the actual wellhead or 
``downhole'' portion of these facilities.
1. Comments Requesting a New Part for Title 49 of the CFR
    The IFR amended parts 191 and 192 to add underground natural gas 
storage regulations. For several reasons, commenters requested that 
PHMSA create a new ``part 19x'' in subchapter D of title 49 of the CFR 
that would contain regulations exclusively for underground storage. 
Generally, their interest was in differentiating the requirements for 
UNGSF from those requirements for other types of regulated gas 
facilities.
    The Associations and some operators recommended that PHMSA remove 
the underground storage regulations from part 192 and place them in a 
new part under subchapter D in 49 CFR. They asserted that moving UNGSF 
regulation to a new part in the pipeline safety regulations would 
clarify the application of the regulations both now and in future 
rulemakings. The commenters stated that because the existing 
definitions of pipeline and pipeline facility in Sec.  192.3 were so 
similar to the definition of underground natural gas storage facility 
(also in Sec.  192.3) that it was unclear how to apply the regulations.
    The Associations also expressed concern that because the IFR placed 
the underground storage regulations in part 192, operators might 
mistakenly apply the engineering regulations specific to other pipeline 
facilities to UNGSFs--or vice-versa. The RPs contain design, 
construction, and IM practices for UNGSFs that the Associations 
believed are considerably different from the practices for other 
pipeline facilities outlined throughout part 192. They provided 
examples of regulations that, if misapplied, might result in unsafe 
practices. The Associations asserted that PHMSA could avoid these 
potential conflicts by placing the UNGSF regulations in a new part 
under 49 CFR subchapter D, separate from part 192.
    Several commenters, including Dow Chemical Company, claimed that 
adding underground storage regulations to part 192 would generate 
confusion. Specifically, commenters said that the IFR was unclear as to 
which sections of part 192 applied to UNGSFs and which ones to other 
gas pipeline facilities. The GPTC expressed the view that the 
definition of underground natural gas storage facilities in Sec.  192.3 
overlapped with the existing definitions of pipeline facilities and 
transmission pipelines and that it believed PHMSA intended to expand 
the regulatory scope of parts 191 and 192 to UNGSFs. However, GPTC 
implied that the overlap between the new definitions and the new 
regulations' placement in part 192 would create confusion as to the 
applicability of the RPs to pipeline facilities already regulated under 
other subparts of part 192.
    Similarly, PG&E requested that the final rule revise the pipeline 
safety regulations to specify which parts of 49 CFR subchapter D 
applied to underground natural gas storage, instead of providing 
clarification through agency guidance materials (e.g., FAQs). They 
stated that PHMSA historically had not incorporated FAQs addressing 
additional programs, such as ``Integrity Management,'' ``Drug and 
Alcohol Testing,'' and ``Gathering Lines,'' into regulatory language. 
PG&E stated that it believed this practice would leave operators at 
risk of being forced to comply with requirements that did not appear in 
regulatory language. Therefore, PG&E encouraged PHMSA to clarify Sec.  
192.12 by adding an exclusion for the subparts of part 192 that would 
not apply to underground natural gas storage. Other commenters shared 
this view and expressed concern that PHMSA would attempt to use FAQs or 
similar guidance documents instead of properly promulgated regulations.
2. Response to Commenters' Request for a New Part
    Section 60101(a)(21) defines the term ``transporting gas'' as ``the 
gathering, transmission, or distribution of gas by

[[Page 8113]]

pipeline, or the storage of gas, in interstate or foreign commerce.'' 
The statute specifically lists the ``storage'' of natural gas as one 
component of ``transporting gas.'' Since all PHMSA's substantive 
regulations pertaining to the transportation of natural gas are in part 
192, PHMSA believes the UNGSF regulations also belong in part 192.
    Along with the public comments, PHMSA reviewed recommendations from 
the Interagency Task Force and a petition for rulemaking from INGAA. 
The Task Force recommended that PHMSA incorporate the RPs into part 
192, with supplemental recordkeeping and reporting procedures as 
necessary. The IFR noted that INGAA had petitioned PHMSA on January 20, 
2016--while the Aliso Canyon accident was still ongoing--to incorporate 
the RPs into part 192. Because UNGSFs are part of the broader natural 
gas transportation systems, part 192 is the most logical place for the 
new substantive regulations. Incorporating the requirements into parts 
191 and 192 also subjects UNGSF operators to the requirements of part 
190, for enforcement and regulatory procedures, and part 199, for drug 
and alcohol testing. Therefore, PHMSA had adopted these recommendations 
and by adding the UNGSF regulations in parts 191 and 192.
    PHMSA agrees that the language in the IFR resulted in a certain 
level of ambiguity about the applicability of Sec.  192.12 to other gas 
pipeline facilities and, vice versa, the applicability of other 
existing regulations to UNGSFs. PHMSA has addressed this issue by 
making two changes in this final rule. First, PHMSA is adding an 
introduction to Sec.  192.12, which provides that the section contains 
minimum requirements for UNGSFs. This introduction means to clarify 
that Sec.  192.12 only applies to UNGSFs and no other pipeline 
facilities. Second, the final rule also modifies the definition of a 
UNGSF to eliminate any potential overlap with other gas pipeline 
facilities covered elsewhere in part 192.
    PHMSA also agrees with the commenters that the FAQs are guidance 
documents to help operators understand and implement rulemakings. FAQs 
are not the basis for PHMSA's enforcement of the rule. However, they 
can and should be used to clarify or explain PHMSA's interpretation of 
the scope and applicability of the regulation. For example, while not 
explicitly stated in the preamble or the amendatory language of the 
IFR, PHMSA explained through FAQs that operators of UNGSFs are subject 
to regulation under 49 CFR part 199, ``Drug and Alcohol Testing.'' Any 
operator of a ``pipeline facility'' that is subject to any subset of 
the part 192 regulations is required to test covered employees for the 
presence of prohibited drugs and alcohol. PHMSA also explained in the 
FAQs that operators of UNGSFs were not required to comply with the 
``Qualification of Pipeline Personnel'' requirements contained in 
subpart N of 49 CFR part 192. The FAQs explained that operators must 
comply with the training requirements in API RP 1170 (section 9.7.5) or 
API RP 1171 (section 11.12), dependent upon the type of storage field. 
Both API RP sections describe general training parameters and 
specifically identify the need to train personnel for normal, abnormal, 
and emergency conditions. Additionally, this final rule makes it clear 
that UNGSFs are not subject to any requirements of part 192, aside from 
Sec.  192.12.

E. Suitability of API RPs 1170 and 1171 as the Basis for Rulemaking

    In the IFR, PHMSA incorporated by reference two industry 
Recommended Practices, API RPs 1170 and 1171, into 49 CFR part 192.
1. Comments Concerning the Suitability of the RPs for Rulemaking
    PHMSA used RPs 1170 and 1171 as the foundation for the new minimum 
safety standards for UNGSFs. Commenters cited the forewords of both 
RPs, which state that the RPs were not intended to substitute for 
Federal or State regulations as the basis for objecting to their use as 
the basis for new regulatory requirements. Other commenters identified 
potential gaps in regulatory coverage in the RPs, such as risk 
management practices for solution-mined salt caverns. For these 
reasons, commenters stated that the RPs were not an adequate basis for 
regulation.
    Some commenters were concerned with the suitability of the RPs as 
the basis for regulations. Texas RRC and EDF criticized PHMSA's 
approach to incorporating the RPs into the underground natural gas 
storage regulations. The Texas RRC stated that the RPs were neither 
drafted nor intended to operate with the force and effect of Federal 
regulations and, as such, should not be adopted as written. Similarly, 
EDF pointed to the scope section of RP 1170, which states that the 
document is ``intended to supplement, but not replace, applicable 
local, State, and Federal regulations.'' Both the Texas RRC and EDF 
said they understood the engineering merit behind the RP, but expressed 
a belief that the RPs were more suitable as guidance material for 
operators.
    Most private citizens urged PHMSA to go beyond the safety 
provisions in the RPs. Notably, these commenters expressed concern over 
the lack of a specific ``risk management'' section in RP 1170 for 
solution-mined salt caverns. They asked that the final rule provide 
additional risk management practices for solution-mined salt caverns.
    A few commenters were concerned that the provisions in the RPs were 
vague, ambiguous, and insufficient in detail. For instance, States 
First said that while the RPs contain substantial information and 
guidance for operators, ``it is [States First's] belief that [the RPs] 
require considerable wording revisions and additions to make them 
effective as regulations.'' Similarly, MDEQ stated that the IFR lacked 
clear timeframes and provided little regulatory oversight and approvals 
for certain actions taken. MDEQ expressed concern that in many 
instances, the IFR left it up to operators to determine the risks 
facing their facilities and the methods for addressing them. It went on 
to say that IFR created inconsistencies and uncertainties in providing 
the level of protection needed. These inconsistencies and uncertainties 
in the IFR, in turn, could make it difficult for State regulators to 
address safety issues for intrastate gas storage operations by 
implementing additional regulations beyond the IFR.
2. Response to Comments Concerning the Suitability of the RPs for 
Rulemaking
    PHMSA disagrees with the commenters' broad assertion that the API 
Recommended Practices are an inadequate basis for regulations. PHMSA 
routinely participates in consensus-standards-setting organizations 
that address pipeline design, construction, maintenance, inspection, 
and repair. These standards represent the best practices of the 
industry and, therefore, should be considered in the development of 
potential regulation. Agency participation in the development of these 
voluntary consensus standards is vital to eliminate the necessity for 
development or maintenance of separate, government-unique standards.
    Further, the PIPES Act specifically directs the Secretary to 
consider ``consensus standards for the operation, environmental 
protection, and integrity management of underground natural gas storage 
facilities'' and ``the recommendations of the Aliso Canyon natural gas 
leak task force established under section 31 of the PIPES Act of 2016'' 
(49 U.S.C. 60141(b)). As

[[Page 8114]]

discussed above, the Interagency Task Force issued a final report, 
titled ``Ensuring Safe and Reliable Underground Natural Gas Storage,'' 
making several recommendations. With respect to API RP 1170 and API RP 
1171, the report recommended that ``[t]he incorporation of API RP 1170 
and 1171 into the part 192 regulations will be an important step in 
improving the safety and reliability of underground gas storage 
facilities.'' \24\ As a result, the report recommended that PHMSA 
consider incorporating the standards into part 192 in a manner that 
would make the standards enforceable.\25\ After consideration of the 
RPs and the comments received concerning their incorporation, PHMSA 
concludes that the standards are sufficient to establish an initial, 
baseline level of regulation with the additions incorporated into this 
final rule. This initial regulatory framework will undoubtedly evolve 
and improve over time as PHMSA gains greater experience in this 
industry.
---------------------------------------------------------------------------

    \24\ ``Ensuring Safe and Reliable Underground Natural Gas 
Storage,'' Final Report of the Interagency Task force on Natural Gas 
Storage Safety; October 2016. See pg. 63-64 of the final report at 
https://www.energy.gov/downloads/report-ensuring-safe-and-reliable-underground-natural-gas-storage.
    \25\ Ibid.
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F. Integrity Management Practices

    Integrity management is PHMSA's risk management program for 
identifying, assessing, and addressing potential threats that can have 
adverse consequences and a finite probability of occurring. The 
regulations in 49 CFR parts 192 (for gas pipelines) and 195 (for 
hazardous liquid pipelines) are a type of integrity management that 
PHMSA has applied to traditional pipeline systems. In place for over 
ten years, PHMSA's integrity management regulations had aided in the 
removal of thousands of defects from pipeline facilities before they 
failed and in the identification of preventive and mitigative measures 
to reduce the likelihood and consequences of failures potentially 
affecting high consequence areas. PHMSA expects that applying similar 
integrity and risk management practices to UNGSFs will have a similar 
effect on improving safety.
    As discussed throughout this final rule, API RP 1170 and API RP 
1171 outline the concepts of risk-based integrity management and 
provide instructions for the risk assessment and analysis process for 
UNGSFs. The IFR required operators of depleted hydrocarbon reservoirs 
and aquifer reservoirs to meet the risk-management requirements 
outlined in section 8 of RP 1171, which resembled PHMSA's existing IM 
program for gas and hazardous liquid pipelines. This section outlines 
the components of a process, including data collection, threat and 
hazard analysis, risk assessment methodology, preventative and 
mitigative measures, risk monitoring, and recordkeeping procedures.
    The IFR did not contain a similar provision for operators of 
solution-mined salt cavern UNGSFs. The term ``Integrity Management'' is 
a systematic approach to analyzing and mitigating risk to promote the 
safe management and operations at a given facility. The IFR required 
operators of solution-mined salt caverns to meet the requirements of RP 
1170, section 10, ``Cavern Integrity Monitoring,'' which directs 
operators to develop a holistic approach to maintaining well integrity 
but does not outline the components of an integrity-management process 
as explicitly as section 8 of RP 1171.
1. Comments Concerning Integrity Management Practices
    As written, the risk-management practices in API RP 1170 (for 
solution-mined salt caverns) lack the specificity of the risk-
management practices in section 8 of API RP 1171 (for depleted 
hydrocarbon reservoirs and aquifer reservoirs). Commenters identified 
the lack of robust risk management practices as a safety gap in the 
integrity program for solution-mined salt caverns and requested that 
the final rule supplement what is currently prescribed in API RP 1170.
    Several commenters expressed concern that the RPs and, 
consequently, the IFR, lacked specific risk management criteria for 
solution-mined salt caverns. As Gas Free Seneca stated, RPs 1170 and 
1171 mirror each other in every respect except for risk management. Gas 
Free Seneca, EDF, and some private citizens requested that the final 
rule add risk management standards for solution-mined salt caverns like 
the standards that exist for depleted hydrocarbon and aquifer 
reservoirs contained in section 8 of RP 1171.
    EDF stated that the IFR called for depleted hydrocarbon and aquifer 
reservoir operators to develop risk management plans that address risks 
and provide plans to mitigate those risks. In its comments, EDF 
suggested that such a plan would be a good supplement to the 
regulations for solution-mined salt caverns. It stated that adding a 
risk management plan as a requirement in the final rule would be 
consistent with the natural gas storage rules being considered by 
California regulators following the incident at Aliso Canyon.
    Gas Free Seneca, States First, EDF, and some private citizens 
requested that PHMSA mandate risk-acceptance criteria for underground 
natural gas storage facilities. Gas Free Seneca and private citizens 
asked that PHMSA set a measurable limit for risk and specify the types, 
frequency, and methods operators must use to collect and conduct risk 
analyses. States First asked that PHMSA set an acceptable level of risk 
so that operators would be required to meet an established standard, 
irrespective of their self-defined ``capabilities.'' EDF added that the 
final rule would benefit from the use of a risk-management 
``heuristic'' such as ``ALARP,'' an acronym that stands for ``As Low as 
Reasonably Practicable.'' According to EDF, ALARP provides a process by 
which the regulated industry and the regulator can work together ``to 
systematically set appropriate levels of risk reduction.'' \26\
---------------------------------------------------------------------------

    \26\ ALARP is a principle more common in European law that sets 
an acceptable level of risk as low as reasonably practicable.
---------------------------------------------------------------------------

2. Response to Comments Concerning Integrity Management Practices
    Based on the commenters' suggestions, and supported by an 
Interagency Task Force recommendation, PHMSA is making several 
enhancements to the integrity management provisions of the final rule. 
First, PHMSA is extending the risk management provisions of section 8, 
to salt-cavern UNGSFs, to the extent they apply to the physical 
characteristics and operations of solution-mined salt caverns, within 
one year of the effective date of the final rule. In other words, the 
final rule requires that UNGSFs using solution-mined salt caverns 
generally conform to the risk management practices that apply to UNGSFs 
using depleted hydrocarbon and aquifer reservoirs.
    There are several reasons for this change. As discussed earlier, 
risk management is a standard concept in the oil and gas industry, 
although different programs may use slightly different terminology. 
Additionally, the Interagency Task Force recommended that PHMSA 
incorporate risk management practices into its regulations. During its 
initial site assessments, PHMSA observed that operators of solution-
mined salt caverns were already in the process of conforming to risk 
management practices like those detailed in section 8. RP 1170 does 
address certain aspects of risk management practices but is less

[[Page 8115]]

comprehensive than RP 1171. For instance, section 10.2 of RP 1170 
requires operators to ``take a holistic and comprehensive approach to 
monitor cavern integrity,'' which would include the identification and 
assessment of risks. Section 10.2 of RP 1170 goes on to say there is no 
single best method to achieve thorough cavern-integrity monitoring, 
thus leaving it up to an operator to evaluate the risks of each 
specific facility.
    While the scope of RP 1171 is specific to depleted-hydrocarbon and 
aquifer reservoirs, much of section 8 is general enough that operators 
can readily apply the practices across all types of UNGSFs. PHMSA 
believes requiring the risk-management practices outlined in section 8 
to all UNGSFs is the most practical method of directing all operators 
to manage the risks of gas storage releases on a case-by-case, 
facility-specific basis. This approach gives operators the flexibility 
to determine what actions are appropriate.
    Second, Sec.  192.12(d) uses slightly different terminology than 
what was used in the IFR to describe the risk management provisions 
that operators must follow. Whereas subsection 8.1 is titled ``Risk 
Management for Gas Storage Operations,'' Sec.  192.12(d) is titled 
``Integrity management program.'' This change is intended to confirm 
that the risk management program under the final rule has been 
broadened beyond what is provided solely under the RPs and that it is a 
variation of the IM programs established under parts 192 and 195 for 
gas transmission pipelines, interstate liquid pipelines, and gas 
distribution systems. The industry generally uses the term IM to 
describe the risk-management provisions of section 8, so it should be 
less confusing and more consistent to use the term IM to refer to all 
four integrity-management programs applicable to PHMSA-regulated 
pipeline facilities,\27\ even though the details of each program vary 
slightly.
---------------------------------------------------------------------------

    \27\ The integrity management provisions for gas transmission 
pipelines are found at Sec. Sec.  192.901 through 192.951, for gas 
distribution pipelines at Sec. Sec.  192.1001 through 192.1015, for 
hazardous liquid pipelines at Sec.  195.452, and for UNGSFs at Sec.  
192.12, as amended by this final rule.
---------------------------------------------------------------------------

    Third, as noted in the FAQs, this initial IM framework for depleted 
hydrocarbon and depleted aquifer reservoir UNGSFs that were constructed 
prior to July 18, 2017, and were subject to section 8 under the IFR, 
had to be in place by January 18, 2018. These operators must now 
implement a full IM program that includes the new provisions in the 
final rule within one year from the final rule's effective date.
    Fourth, this final rule requires a slightly different process for 
UNGSF operators to develop a robust IM program, depending upon whether 
the facility is a depleted hydrocarbon or a depleted aquifer reservoir 
or whether it is a solution-mined salt cavern. For the former, the 
first step is to put together an initial ``framework'' based on the 
provisions of section 8, including:
     A general discussion or definition of risk management;
     Data collection and integration;
     Threat and hazard identification and analysis;
     Risk assessment;
     Preventive and mitigative measures;
     Periodic review and reassessment; and
     Recordkeeping.
    For existing solution-mined salt cavern UNGSFs, they must implement 
a full IM program within one year from the effective date of the final 
rule. For new facilities constructed after the effective date of the 
final rule, they must have a full IM program in place before they 
commence operations. In addition, the final rule allows solution-mined 
salt cavern UNGSFs greater flexibility in meeting the provisions of 
section 8 by requiring that they meet only those provisions of section 
8 that are applicable to the physical characteristics and operations of 
a solution-mined salt cavern. The two timelines differ because 
operators of solution-mined salt cavern facilities did not receive 
notice of having to meet the IM provisions of section 8 ``that are 
applicable to the physical characteristics and operations of a 
solution-mined salt cavern UNGSF.'' PHMSA believes that such a 
limitation on the IM program for solution-mined salt caverns is 
reasonable and readily ascertainable by operators of such facilities.
    Fifth, in addition to the general framework outlined in section 8, 
the final rule includes several specific IM requirements for all UNGSF 
operators. Each operator's plan must include the following:
     A plan for developing and implementing each program 
element to meet the requirements of the final rule;
     The roles and responsibilities of UNGSF staff tasked with 
developing and implementing the IM program;
     An outline of the IM procedures to be developed;
     A plan for how staff will be trained in awareness and 
application of the operator's IM program;
     Timelines for implementing each IM program element, 
including the risk analysis and baseline risk assessments; and
     A plan for how to incorporate information gained from 
experience into the IM program on a continuous basis.

Because these are new, more specific requirements than those contained 
in the IFR, operators of existing UNGSFs will have an additional year 
to comply.
    Sixth, PHMSA establishes a schedule for conducting the initial or 
``baseline'' assessments for each reservoir or cavern and all wells. 
PHMSA has based this schedule on commenters' recommendations to use a 
``phase-in'' timeline, similar to the UNGSF FAQs published in April 
2017. The final rule requires that operators complete all baseline 
assessments for reservoirs and salt caverns and 40 percent of the 
baseline assessments for individual wells within four years from the 
effective date of this final rule. Operators must start with the 
higher-risk wells, as identified through the operator's risk-analysis 
process. The remaining 60 percent must be completed within seven years 
from the effective date of this final rule.
    Seventh, the final rule requires that operators conduct periodic 
reassessments under API RP 1171, subsection 8.7, on a risk-based 
schedule. This final rule establishes that reassessment intervals must 
be no more than seven years. PHMSA assumed that the stress conditions 
for the downhole piping used at the well site are similar to the stress 
conditions for buried pipe. Because of this, PHMSA chose a seven-year 
reassessment (maximum) interval to be consistent with other gas 
pipeline regulations. However, an operator could determine its 
reassessment interval should be less than seven years based on its 
risk-based assessments.
    Seventh, the final rule makes clear that operators may use one or 
more risk assessments completed before the effective date of the rule 
to establish a baseline assessment, so long as they meet the 
requirements of section 8 of RP 1171, and continue to be relevant and 
valid for the current operating conditions and environment. These 
requirements are consistent with the FAQs published in April 2017.\28\ 
This requirement is intended to prevent operators from reproducing 
assessments that already meet the requirements of this final rule. The 
criteria and timing for reassessments should be determined using 
results from baseline assessments and updated risk analyses in 
accordance with section 8. Operators may also conduct new or additional 
assessments to supplement prior assessments as

[[Page 8116]]

necessary to establish a thorough understanding of a facility's risks.
---------------------------------------------------------------------------

    \28\ https://www.phmsa.dot.gov/pipeline/underground-natural-gas-storage/ungs-frequently-asked-questions.
---------------------------------------------------------------------------

    Eighth, the final rule requires that operators maintain IM records 
in the same manner as pipeline operators are required to keep records 
under other IM provisions in parts 192 and 195. Maintaining IM records 
is critical if operators are to properly understand their systems, 
track and learn from experience, and to make continuous improvements. 
These records document how and why decisions are made to identify 
risks, set priorities among risks, conduct assessments, and identify 
and carry out preventive and mitigative measures. Further, operators 
must maintain IM records for the life of the UNGSF to demonstrate 
compliance with all the requirements under Sec.  192.12(d). This level 
of documentation includes any calculation, amendment, modification, 
justification, deviation and determination made, and any action that is 
taken to implement and evaluate any element of an IM program. This 
level of documentation is the same standard found in Sec.  192.947 for 
gas transmission systems and Sec.  195.452(l) for hazardous liquid 
transmission systems.
    Regarding the commenter's suggestion that PHMSA should apply a 
``risk-tolerance'' model such as ALARP, PHMSA believes such a change is 
unnecessary. Integrity Management (IM) is one of many different 
varieties of risk management models used by different industries and 
organizations to handle safety risks to people and the environment. 
PHMSA's IM regulations require pipeline operators to identify the 
unique risks specific to their facilities comprehensively and to 
address those risks through a continuous program of gathering and 
analyzing data and learning from experience. PHMSA's approach places 
the onus on operators to identify, prioritize, and handle the risks 
posed by pipeline accidents. The IM requirements in this final rule are 
designed to be interpreted and applied essentially the same as the IM 
regulations currently applied to gas and hazardous liquid pipelines.
    PHMSA believes that the integrity program outlined in Sec.  
192.12(d) and the RPs provides a flexible model that accounts for the 
diversity and variability of all UNGSFs, so long as the practices are 
risk-based and rigorously applied. To introduce a new model, such as 
ALARP, just for underground gas storage facilities and not other 
pipeline facilities, could be confusing for operators, PHMSA 
inspectors, and the public. Further, PHMSA is not aware of evidence 
that the ALARP model would provide an increase in safety.

G. Notification Criteria Under 49 CFR Part 191 for Changes at a 
Facility

    The IFR added reporting requirements in 49 CFR part 191. PHMSA 
requires four types of reports from operators of UNGSFs: (1) Annual 
reports, (2) incident reports, (3) safety-related condition reports, 
and (4) National Registry information. PHMSA required this information 
because there was no that UNGSF operators follow the same provisions 
that gas pipeline operators must follow for providing PHMSA with 
notification of changes at their facilities.
    Regarding the last type of report, PHMSA required National Registry 
information to identify the facility operator responsible for operators 
through an Operator Identification Number (OPID). The IFR required 
operators to notify PHMSA no later than 60 days before certain changes 
occur, including:
     Construction of a new UNGSF facility;
     Abandonment, drilling, or ``workover'' of an injection, 
withdrawal, monitoring or observation well. Concerning well workovers, 
the IFR stated that such work included the replacement of a wellhead, 
tubing or casing; and
     Changes in the entity (including company, municipality, 
etc.) that is responsible for an existing UNGSF and the acquisition or 
divestiture of an existing facility.
    PHMSA clarified the IFR's notification requirements through April 
2017 FAQs. For example, an operator should notify PHMSA of a 
``replacement of a wellhead, tubing or casing.'' The FAQs said a 
``replacement'' in this context meant the ``complete removal of the 
existing component and replacement with a new component (including 
replacement of wellhead, tubing, or casing).'' The FAQs further 
explained that there was no need for an operator to notify PHMSA of 
routine maintenance or repairs to existing components. The FAQs went on 
to say that operators should submit separate notifications for each 
storage field, but could bundle multiple activities within the same 
storage field in a single notification.
1. Comments on Notification Criteria Under 49 CFR Part 191 for Changes 
at a Facility
    The IFR required UNGSF operators to notify PHMSA no later than 60 
days before certain changes took place at their facilities took place, 
including changes in the operator of a facility and major new 
construction, as is currently required for other pipeline facilities. 
Operators found this reporting requirement excessive and recommended a 
monetary or activity threshold to reduce the volume of notifications. 
These commenters believed that the IFR's 60-day notification 
(reporting) requirement for new construction and construction-related 
activities was ambiguous and would result in excessive notifications. 
Some commenters expressed concern that the provision failed to exempt 
emergencies where advance reporting would be impractical.
    LMOGA and TransCanada contended that PHMSA's notification 
requirement would duplicate their reporting burdens and cause delays 
because operators already had to notify states of construction 
activities and permitting. LMOGA expressed concern that a 60-day-notice 
to PHMSA for certain construction activities, such as well workovers, 
could shut down wells for an unnecessary amount of time. It stated 
that, currently, work permits for well workovers are issued by states 
in one to three days. TransCanada contended that PHMSA should remove 
the 60-day-notice requirement for new construction from the final rule 
altogether. It suggested that PHMSA could capture this same information 
through the annual report and safety-related condition reports instead 
of creating a separate notification requirement.
    GPTC, PG&E, and others suggested other ways to streamline or reduce 
the notification burden involving new construction. For example, GPTC 
suggested that the final rule limit advance notifications to only those 
well workovers where a well was killed, a plug placed in the well for 
work, or a rig installed.
    Another suggestion from PG&E was for PHMSA to adopt a monetary 
threshold for new-construction notifications, provide an exemption for 
emergency work, and define what activities would constitute a ``well 
workover.'' Regarding the monetary threshold, PG&E recommended that 
PHMSA only require operators to report well-workover and new-
construction activities that cost more than $2 million. The company 
noted that PHMSA currently limits pipeline notifications \29\ to those 
projects involving a certain minimum mileage or monetary threshold; it 
argued that applying similar thresholds for UNGSFs could reduce the 
reporting burden on operators.
---------------------------------------------------------------------------

    \29\ 49 CFR 191.22(c)(1)(i).

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

[[Page 8117]]

2. Response to Comments on Notification Criteria Under 49 CFR Part 191 
for Changes at a Facility
    The purpose of the 60-day notification requirement in the IFR is to 
alert PHMSA of upcoming critical well work that requires an operator to 
control well pressure. One example of such a well-control activity is 
well abandonment. If an operator incorrectly performs an abandonment, 
then brine fluid or natural gas may migrate through the wellbore and 
escape into drinking-water aquifers or to the surface. If notified in 
advance, PHMSA will have the opportunity to review the operator's pre-
work plan and observe the in-progress work. Ultimately, this process is 
beneficial for the operator and public safety because it ensures a 
comprehensive assessment of the operators' methods. Such notifications 
could prevent an incident or more costly remediation work. PHMSA will 
have the opportunity to review an operator's records of the project 
but, because most of the work is underground, reviewing the work in 
real-time is ideal.
    PHMSA agrees with the commenters that it should narrow the scope of 
the notifications for changes to a facility that would eliminate 
excessive reporting of minor or routine maintenance. Accordingly, this 
final rule limits required notifications to PHMSA to only those 
involving new construction and major maintenance work. Specifically, 
the final rule provides that operators must notify PHMSA of (1) any new 
facility construction; (2) maintenance work that requires a workover 
rig and costs $200,000 or more for labor, materials, and services; and 
(3) any plugging or abandonment activities, regardless of cost.
    The scope of this modified notification requirement is limited to 
only those types of activities that require adherence to specific 
methods and techniques to prevent damage to the formations and to 
safely control pressure in the well. Bringing in a workover rig marks a 
step-change in the degree of complexity and scope of work. The presence 
of a workover rig means the operator is opening the well, rather than 
just doing some wing valve work at the surface. Opening a well 
(requiring a workover rig) usually infers serious maintenance or repair 
work, performing extensive logging and integrity evaluations, or 
replacement of downhole components.
    Concerning the $200,000 maintenance-work threshold, PHMSA has not 
indexed this exact dollar amount across all states and activity types. 
During preliminary inspections, PHMSA observed what high-risk 
activities were occurring in the field and generally how much it costs 
operators to complete those maintenance activities. PHMSA is aware that 
the costs of pressure-control and remediation activities vary 
considerably, depending upon the depth of the well, pressure, casing 
type and size, and other factors. However, PHMSA believes this is an 
appropriate threshold level that captures the higher-risk activities 
and still reduces the volume and burden of notifications. There is the 
possibility that a workover rig is needed for some minor issues, where 
the cost falls below the 200k threshold. Again, most major activities 
with a workover rig will cost more than $200,000, thus triggering this 
type of notification. Note that PHMSA also allows operators to report 
multiple well activities within the same storage field in a single 
notification.
    PHMSA also recognizes that the IFR inadvertently omitted an 
exception for emergency maintenance or repairs. If an operator 
reasonably determines that it needs to do work immediately, for safety 
reasons, then it should not delay the work because of the 60-day 
notification requirement. Accordingly, the final rule adds a provision 
that allows operators to notify PHMSA as soon as practicable in 
instances where 60-day notice is not feasible due to an emergency. In 
such cases, an operator must promptly respond to the emergency, notify 
PHMSA as soon as practicable, and document the emergency and the reason 
for any delay in notification.

H. The States' Role in Regulating UNGSFs

    There are approximately 403 active underground natural gas storage 
facilities (UNGSFs) in the United States, with about a 60/40 split 
between interstate and intrastate facilities. Interstate UNGSFs serve 
interstate facilities, and PHMSA has exclusive pipeline safety 
jurisdiction over the design, construction, operation, and maintenance 
of these facilities. Intrastate UNGSFs, on the other hand, are 
facilities that provide gas storage for intrastate pipelines, most 
notably local gas distribution companies (LDCs). Generally, these 
intrastate gas pipeline facilities have been subject to State 
regulation by its public utility commission or oil and gas commission. 
Intrastate UNGSFs continue to be subject to State regulation, but only 
if the applicable State authority has filed a certification with PHMSA 
to participate as a full State partner under the new Federal program 
and receive Federal funding through PHMSA.
    The Federal regulatory program for UNGSFs has been set up to mirror 
the existing Federal-State pipeline regulatory partnership for gas and 
hazardous liquid pipelines as established by the Natural Gas Pipeline 
Safety Act in 1968 and the Hazardous Liquid Pipeline Safety Act of 
1979, respectively. Under this system, Congress has conferred on the 
Department primary jurisdiction over all natural gas and hazardous 
liquid (primarily oil) pipelines in or affecting interstate commerce 
but has preserved the states' role in regulating intrastate pipelines, 
as long as the State that chooses to submit an annual certification to 
PHMSA and agrees to enforce the minimum Federal standards in addition 
to any State regulations compatible with the Federal standards.
    The PIPES Act directed PHMSA to expand its pipeline-safety 
regulatory program to include the storage of natural gas incidental to 
transportation, using this same Federal-State model. Just as various 
states had previously regulated intrastate natural gas pipelines before 
the passage of the Natural Gas Pipeline Safety Act of 1968, so too have 
many states regulated UNGSFs prior to the passage of the PIPES Act and 
issuance of the IFR. These states will be able to continue this 
important safety role as partners with PHMSA.
    Under the IFR and this final rule, intrastate UNGSF facilities will 
be regulated in one of two ways. Depending upon State law, they will be 
regulated either by a certified State entity (e.g., public utility 
commission or oil and gas commission), or, in the absence of a 
certified State partner, by PHMSA. Notably, section 12 of the PIPES Act 
expressly allows a State authority to adopt additional or more 
stringent safety standards for intrastate UNGSFs, provided such 
standards are compatible with the minimum Federal requirements. PHMSA 
interprets this to mean that any State authority that has filed an 
annual State certification with PHMSA under 49 U.S.C. 60105 to regulate 
UNGSFs may regulate and enforce its own additional or more stringent 
regulations against intrastate UNGSFs that fall under that authority's 
State jurisdiction, to the extent that the additional State standards 
are compatible with the Federal safety regulations. This arrangement is 
the same as the States' authority to regulate all other intrastate 
pipeline facilities under parts 192 and 195.
    Accordingly, States that had UNGSF regulations before the adoption 
of the IFR may continue to implement any

[[Page 8118]]

additional or more stringent regulations that they currently enforce 
with respect to intrastate facilities, to the extent that such 
regulations are compatible with the minimum standards set by this final 
rule. For a State wanting to expand its authority to inspect interstate 
facilities under the final rule, it will be able to apply to PHMSA for 
discretionary interstate agent status under 49 U.S.C. 60106(b), just as 
a State authority today, may carry out such a role for other oil and 
gas pipeline facilities.
    It is worth noting that neither the PIPES Act nor this final rule 
alters the existing role of the States in the siting or permitting of 
UNGSFs or their regulation of natural gas production. PHMSA has never 
exercised regulatory control over these issues for pipeline and will 
not be doing so under the final rule. Instead, the PIPES Act provides 
that all UNGSFs incidental to gas ``transportation'' are now subject to 
Federal minimum safety standards promulgated by PHMSA. Section 12 of 
the PIPES Act directs PHMSA to exercise this authority in conjunction 
with its State partners in the same manner as other pipeline facilities 
are regulated.
    This means FERC and the States will continue to exercise their 
respective authorities over the permitting of UNGSFs. FERC reviews 
applications for the construction and operation of UNGSFs owned by 
interstate gas pipeline operators and that are integrated into their 
pipeline systems. In its application review, FERC requires an applicant 
to certify that it will comply with DOT safety standards. While FERC 
has no jurisdiction over pipeline safety, PHMSA and FERC actively 
collaborate to exercise their respective responsibilities.\30\
---------------------------------------------------------------------------

    \30\ Page 28. https://www.ferc.gov/market-oversight/guide/energy-primer.pdf.
---------------------------------------------------------------------------

    PHMSA received several comments regarding the effect of the IFR on 
the role of the states in UNGSF regulation. These comments dealt 
primarily with concerns expressed by State regulators and gas-storage 
operators over PHMSA's role and the nature of the Federal-State 
partnership under this new regulatory scheme. These commenters also 
asked PHMSA to explain the roles of the various parties in permitting 
UNGSFs, to discuss the potential conflicts that may arise between 
existing State regulations affecting underground storage and the new 
Federal minimum safety standards and the degree to which certain 
existing State regulations will continue to apply to interstate UNGSFs. 
Of particular concern was whether the IFR could serve to undermine or 
reduce the existing level of safety and environmental protection that 
several States have been applying to interstate UNGSFs, especially 
where certain State standards could arguably be viewed as broader or 
more stringent than the RPs being adopted in the final rule. These 
comments are discussed below in more detail.
1. Comments on State Permitting of UNGSFs
    In its comments, the Texas RRC asked PHMSA to clarify the States' 
role in permitting UNGSFs and commented that the IFR provided no 
specific details regarding permitting areas that fall to the 
states.\31\ The commission noted that while the IFR accurately stated 
that permitting of gas wells is not a PHMSA function, PHMSA had 
incorrectly concluded: ``that the traditional role of permitting 
intrastate facilities falls to the states and the permitting of 
interstate facilities falls to the Federal Energy Regulatory Commission 
(FERC).'' According to the Texas RRC, ``FERC is not set up to conduct 
permitting of individual wells, ensuring proper notification is 
provided to all entitled parties, reviewing and adequately protecting 
groundwater, and protecting correlative rights.'' Conversely, the Texas 
RRC explained that under Texas law, the Texas RRC is directed to 
regulate the downhole portion of UNGSFs to fulfill its mandate to 
conserve State natural resources and to protect the environment. 
Therefore, it argued, ``all of these functions must fall to the State 
regardless of whether a well is part of an intrastate or interstate 
facility.'' Finally, the Texas RRC argued that the failure of PHMSA to 
properly address these scenarios ``indicates a lack of a clear 
understanding of underground natural gas storage and the historical 
role many states have had in its successful regulation of underground 
hydrocarbon storage.''
---------------------------------------------------------------------------

    \31\ See State of Texas v. PHMSA, No. 17-60189 (5th Cir. Mar. 
17, 2017).
---------------------------------------------------------------------------

    Similarly, Dow Chemical asserted that many states had established 
successful regulations and standards for permitting, operations, 
maintenance, monitoring, and other issues related to UNGSFs. The 
company pointed out that states with underground-storage safety 
regulations typically regulate both intrastate and interstate 
facilities. Along with Dow Chemical, LMOGA, MDEQ, and the Texas RRC 
recommended that PHMSA consult with State regulatory agencies to avoid 
unnecessary reporting and compliance programs and to learn from the 
states' experience in regulating UNGSFs as it continues to develop 
Federal regulations.
2. Response to Comments on the State Permitting of UNGSFs
    As for the comments seeking greater clarity on how the IFR affects 
State permitting of UNGSFs, PHMSA has not made any changes to the 
regulatory text because PHMSA does not have the authority to prescribe 
the location or siting of UNGSFs. This final rule also does not deal 
with permitting, directly. Section 12 of the PIPES Act expressly states 
that the Act shall not be construed to authorize PHMSA ``to prescribe 
the location of an underground natural gas storage facility'' or ``to 
require the Secretary's permission to construct'' a UNGSF.
3. Comments on State Regulation of UNGSFs Associated With Gas 
Production
    IPAA, EDF, and Hilcorp requested that PHMSA clarify how the IFR 
applied to UNGSFs associated with gas-production facilities. IPAA 
stated that the Pipeline Safety Laws do not provide PHMSA with 
authority to regulate gas-production facilities, citing 49 U.S.C. 
60101(a)(21)(A) and 60101(a)(22)(B). IPAA, EDF, and Hilcorp requested 
that PHMSA add an exception to part 192, specifically excluding UNGSFs 
that are ``in direct support of'' (Hilcorp) or that are ``co-located 
with and used to support of'' (IPAA) production operations.
    IPAA gave two examples of the types of production-related UNGSFs 
located in active production fields that are used to manage production 
operations, rather than providing ``commercial storage services.'' The 
first type was facilities that store gas from a production field but 
has not yet entered a PHMSA-regulated pipeline. The second type was 
UNGSFs that are used for gas production purposes ``after being 
delivered to the production field in a PHMSA-regulated pipeline.'' In 
other words, they store gas that has either not yet entered 
transportation or that has ended transportation. Under both scenarios, 
IPAA contended, the stored gas at these facilities is not incidental to 
transportation but is used to support gas production. According to 
these industry commenters, such UNGSFs are used in the process of 
extracting natural gas from the ground and should not be treated as 
providing storage incidental to transportation under the Pipeline 
Safety Laws.

[[Page 8119]]

4. Response to Comments on UNGSFs Associated With Gas Production
    The PIPES Act directed PHMSA to establish minimum Federal standards 
for all UNGSFs that store natural gas incidental to transportation. 
Again, the PIPES Act does not alter or expand PHMSA's jurisdiction as 
it has traditionally been applied to natural gas production or 
hazardous liquid production facilities. While PHMSA has never exerted 
jurisdiction over gas pipeline facilities that are engaged exclusively 
in production and has long recognized the authority of states to 
regulate the permitting and siting of pipelines and to protect 
groundwater and other State natural resources. Only after 
transportation has begun and before delivery to an end-user is there 
any issue of PHMSA jurisdiction, which is limited to the transportation 
of gas and hazardous liquids.
    This is analogous to PHMSA's regulation of other types of temporary 
storage of hazardous liquid in transit. For example, petroleum being 
transported by pipeline is often stored temporarily along the line in 
one or more breakout tanks. These tanks are used to relieve surges or 
receive and store hazardous liquid transported by pipeline for eventual 
re-injection and continued transportation by pipeline (49 CFR 195.2). 
Similarly, under this final rule, a UNGSF is defined as a gas pipeline 
facility ``that stores natural gas underground and incidental to the 
transportation of natural gas'' in interstate or foreign commerce.
    PHMSA interprets this to mean that if a UNGSF is used in any way to 
store gas that is received from a PHMSA-regulated pipeline and returns 
any of that stored gas to transportation by pipeline, then such a 
facility is incidental to transportation and therefore covered by this 
final rule. Even if some of that gas is used to support production 
operations or is mingled with produced gas that has not yet entered 
transportation, the storage facility itself will be treated as a UNGSF 
under the final rule and will be subject to PHMSA's full jurisdiction.
5. Comments on States' Regulation of Intrastate UNGSFs
    Several commenters expressed concern that the IFR potentially 
conflicted with existing State regulation of intrastate UNGSFs and that 
the IFR lacked clarity on how such conflicts could be avoided or 
minimized. MDEQ, for instance, commented that its Oil, Gas and Minerals 
Division ran a regulatory program affecting many safety and 
environmental issues covered by the RPs and that ``Michigan's existing 
regulations are needed to fill gaps in the IFR particularly in the 
areas of permitting, liquid waste handling and disposal; and 
environmental protection from liquid hydrocarbons, brines, and other 
liquid contaminants.'' The agency further commented that the IFR 
``makes no mention of pollution prevention, nor does it set standards 
for remediation of spills.'' It noted that many UNGSFs are located in 
oil reservoirs that still produce liquid hydrocarbons and brine, and 
that the State of Michigan has comprehensive regulations covering 
pollution prevention, groundwater monitoring, remediation, and clean-up 
activities. In short, the State urged PHMSA to ``recognize the states' 
role in these areas.''
6. Response to Comments on the States' Regulation of Intrastate UNGSFs
    First, PHMSA recognizes and supports the role that many states have 
played for many years in the field of underground gas storage. Nothing 
in the IFR or this final rule is intended to minimize or diminish the 
states' role in ensuring the safety of UNGSFs, protecting the 
environment, or safeguarding critical State resources. Section 12 of 
the PIPES Act, however, mandates that PHMSA regulate all UNGSFs that 
storing natural gas incidental to transportation. Under 49 U.S.C. 
60104(c) and the recently-enacted 49 U.S.C. 60141(e), states with 
existing regulations may continue to regulate intrastate gas storage 
facilities to the extent that the proper State authority becomes 
certified by PHMSA and the State regulations are compatible with the 
new Federal minimum safety standards.
    Second, the PIPES Act and this final rule do not modify or 
undermine established principles of Federal preemption law as applied 
to pipeline safety. Any State regulation affecting PHMSA's exclusive 
jurisdiction over the safety of interstate pipeline transportation 
facilities is, and always has been, preempted by the Pipeline Safety 
Laws.\32\ The enforceability of existing or new State regulations 
affecting gas production, storage, plugging, or other areas such as 
mineral rights, depends on whether the State regulations are based on 
an independent basis under State law and cannot be considered safety 
regulations preempted by the PIPES Act, which is necessarily a case-by-
case determination.
---------------------------------------------------------------------------

    \32\ See, e.g., Colorado Interstate Gas Company v. Wright, 707 
F. Supp. 2d 1169 (D. Kan. 2010).
---------------------------------------------------------------------------

    Third, the PIPES Act and this rule represent a major step forward 
in extending minimum Federal safety standards to all interstate gas 
storage facilities, regardless of whether individual states have 
already adopted regulations governing storage facilities or whether 
individual interstate operators have voluntarily complied with existing 
State regulations. As PHMSA discussed in the IFR, interstate UNGSF 
facilities would not be subject to any regulatory safety requirements 
in the absence of this Federal action.
    Fourth, PHMSA fully recognizes that states with UNGSFs typically 
have various regulations in place governing the construction, 
remediation, and plugging of gas wells. Before the IFR went into 
effect, many interstate UNGSF operators relied on these State 
regulations to help develop best practices. State safety jurisdiction, 
however, extends only to intrastate UNGSFs. Regulations differ from 
State to State, making it difficult for operators to maintain 
consistent performance across all their interstate facilities. Finally, 
PHMSA will incorporate lessons learned from operators and states 
implementing this final rule in the form of guidance and additional 
rulemakings. PHMSA understands that seeking input from states is a 
vital component in developing an effective underground natural gas 
storage program at the Federal level.
    As for the comments regarding potential conflicts between existing 
State regulation of intrastate UNGSFs, three points should be made. 
First, many State agencies enjoy independent authority under their own 
particular State's laws to regulate UNGSF involving public health, 
protection of groundwater, allocation of mineral rights, and similar 
areas not involving safety. Under established Federal preemption law, 
States may regulate in such areas that are not preempted expressly by 
Federal law or regulation.
    In the field of underground natural gas storage, Congress, through 
the PIPES Act, has conferred authority on the Secretary (and delegated 
to PHMSA) to provide for the safety of natural gas storage facilities 
incidental to transportation, just as it has for other oil and gas 
pipeline facilities. This authority covers the design, construction, 
operation, and maintenance of UNGSF facilities. States are precluded 
from regulating the safety of UNGSFs to the extent that such State 
regulations conflict with PHMSA's safety-related regulations. To 
determine whether specific State regulations are preempted by the PIPES 
Act and this final rule may require a fact-specific analysis of whether 
a particular State regulation has been preempted, an

[[Page 8120]]

analysis that falls within the purview of State and Federal courts. 
Such preemption determinations have routinely been made by the courts 
to resolve challenges to State and local governments' authority to 
regulate gas and hazardous liquid pipelines.
    Second, any potential conflict between existing State regulations 
governing intrastate UNGSFs and Federal safety regulations disappears, 
in most cases, in those states that have submitted annual 
certifications to PHMSA and become UNGSF State partners. All State 
partners in this program will have the authority to adopt and enforce 
additional or more stringent safety regulations than the minimum 
Federal standards set forth in the IFR. PHMSA anticipates and hopes 
that many states, such as Texas, Michigan, and other commenters that 
already have existing regulations affecting intrastate UNGSF safety, 
will decide to partner with PHMSA and enjoy the enhanced authority, 
Federal funding, and other benefits that accompany State certification.
    Third, PHMSA encourages and supports State regulatory programs that 
help ensure all UNGSFs, both intrastate and interstate, address 
resource conservation, environmental protection, land use, emergency 
response, and other important issues affecting gas wells and storage 
outside the realm of safety.
    PHMSA agrees with MDEQ's comments and encourages MDEQ to examine 
its existing State UNGSF regulations to determine whether any of them 
are safety-related standards that could be preempted by this final rule 
in the event Michigan decides that it does not wish to become a 
certified State partner for intrastate UNGSFs. If Michigan does become 
a State partner for UNGSFs, then MDEQ (or other State authority in 
Michigan) will be able to apply additional or more stringent safety 
standards, provided they are ``compatible'' with the minimum Federal 
standards prescribed under the Pipeline Safety Laws and this final 
rule. If it chooses not to become a State partner for UNGSFs, then the 
Federal minimum safety standards will apply to all intrastate UNGSFs in 
Michigan, and PHMSA will inspect such facilities and enforce the 
Federal minimum standards against all intrastate UNGSFs in the State.
7. Comments on States' Regulation of Interstate UNGSFs
    Some commenters, including EDF and the Interstate Oil and Gas 
Compact Commission, expressed concern that the IFR did not go far 
enough in exercising jurisdiction over UNGSFs in a manner that 
optimized existing State regulations. EDF commented that the new 
Federal regulations would create a ``ceiling'' on State regulations for 
the permitting, drilling, completion, and operation of underground 
storage wells that have also been applied to interstate facilities. EDF 
acknowledged that while interstate facilities are under the exclusive 
safety jurisdiction of PHMSA, intrastate UNGSFs are frequently subject 
to both safety regulations promulgated by PHMSA and to other gas-
storage rules promulgated by State regulators that generally apply to 
all gas wells in their particular states. EDF expressed the fear that 
interstate UNGSF operators who had been ``voluntarily obeying State 
rules responding to the State's unique geology, level of subsurface 
activity, competing surface activities and general appetite for risk 
may, with the cover of PHMSA's IFR, decline to continue following those 
rules, possibly to the detriment of safety and the environment.''
    To address this concern, EDF asked PHMSA to include two specific 
provisions in the final rule. First, it asked PHMSA to distinguish 
between those State regulations of general applicability to all oil and 
gas wells (i.e., those falling within the jurisdiction ceded to states 
under the Natural Gas Act of 1938) and those addressing the special 
risks intrinsic to gas storage wells. EDF requested that PHMSA direct 
interstate operators to adhere to State regulations for permitting, 
drilling, completion and operation of storage wells, but ``only to the 
extent the regulations address risks of general applicability to all 
oil and gas wells and where it is not impossible to comply with both 
the State regulations and PHMSA requirements.''
    Second, EDF asked PHMSA to require interstate operators in states 
having adopted ``storage'' regulations to identify all State rules that 
an operator believes are ``storage'' rules and address those rules in 
their risk management plans as part of the operators' preventive and 
mitigative measures to address ``special risks intrinsic to gas 
storage.'' According to EDF, this would serve to preserve the efforts 
made by some states to ensure safety and environmental protections 
imposed in the face of no minimum Federal standards.
8. Response to Comments on the States' Regulation of Interstate UNGSFs
    As noted earlier, EDF and other commenters have pointed out that a 
number of interstate UNGSF operators in states with mature regulatory 
programs in place have been ``voluntarily'' obeying State rules. PHMSA 
acknowledges EDF's concern that some interstate operators may choose to 
no longer voluntarily comply with State UNGSF regulations that go 
beyond the new minimum Federal standards embodied in the final rule. 
However, the Federal standards do not disincentivize the voluntary 
compliance that was previously occurring before the IFR went into 
effect, provided that the voluntary compliance is compatible with the 
Federal standards. Therefore, it seems unlikely that an interstate 
operator who is already voluntarily complying with existing State 
safety-related standards would stop doing so because of this final rule 
unless voluntary compliance were to result in non-compliance with the 
Federal standard. Further, this is the same situation that exists with 
other State regulations that may affect gas and hazardous liquid 
pipelines and with which interstate operators may or may not choose to 
comply. For these reasons, PHMSA declines to modify the final rule to 
require interstate operators to take such State regulations into 
account in their IM plans or other procedures. The agency believes it 
would be inconsistent and impracticable to require operators to 
evaluate and include in their plans and procedures certain provisions 
of State regulations for UNGSFs but not for other pipeline facilities. 
This would put PHMSA in the untenable position of elevating certain 
State regulations for all interstate UNGSF operators but not for other 
State pipeline regulations. If PHMSA learns of State regulations that 
should be applied more broadly for all interstate UNGSF operators, it 
may consider amending its regulations through notice-and-comment 
rulemaking to make them applicable uniformly among all interstate 
operators.

I. Definitions and Terminology

    The IFR added a definition for ``underground natural gas storage 
facility'' at 49 CFR 191.3 based on the definition provided in section 
12 of the PIPES Act. The IFR's definition included the wellhead, 
downhole components, and associated onsite structures that lay within 
the scope of PHMSA's regulatory authority. The IFR provided no 
additional definitions.
1. Comments Regarding Definitions and Terminology
    Several commenters asked that PHMSA modify the definition of 
``underground natural gas storage facility'' in the final rule and to 
clarify or define other terms not defined in the IFR. Two commenters 
requested that

[[Page 8121]]

PHMSA create separate definitions for interstate and intrastate 
facilities. They said that clarification in the final rule would 
prevent jurisdictional confusion at the State level and enable their 
organizations to apply the rules more predictably.
    Operators recommended a revised definition of ``underground natural 
gas storage facility,'' while others asked that PHMSA clarify the terms 
``workover'' and ``modified well.''
    The Associations recommended that PHMSA revise the definition of 
``underground natural gas storage facility'' to avoid confusion with 
other subparts of 49 CFR part 192. They were concerned that the 
definition in the IFR included ``piping, rights-of-way, property, 
buildings, compressor units, separators, metering equipment, and 
regulator equipment,'' terminology that could imply components of a 
UNGSF were covered by both the underground natural gas storage 
regulations at Sec.  192.12 and other provisions in part 192. They 
recommended that the definition of ``underground natural gas storage 
facility'' be amended to exclude ``facilities covered by part 192 of 
this chapter.''
    The Associations further noted that the definition of a UNGSF 
included the term ``solution-mined salt cavern reservoir.'' They stated 
that the term ``reservoir'' is inaccurate in reference to salt caverns 
and recommended that PHMSA use the term ``a solution-mined salt 
cavern'' for technical accuracy. Similarly, the GPTC recommended that 
the final rule revise the definition of UNGSF to align with the scope 
of the RPs 1170 and 1171.
    Similarly, PG&E recommended that PHMSA replace the definition of 
``underground natural gas storage facility'' at Sec.  192.3 with the 
following:

    ``Underground gas storage facility means a facility that stores 
natural gas in an underground facility incidental to natural gas 
transportation, which is constructed from a depleted hydrocarbon 
reservoir, an aquifer reservoir, or a solution-mined salt cavern. In 
addition to the reservoir, this also includes the injection, 
withdrawal, monitoring, observation wells, and associated wellhead 
equipment within the facility.''

PG&E also recommended that PHSMA remove the phrase ``including 
injection, withdrawal, monitoring, or observation well for an 
underground natural gas storage facility'' from the criteria for 
submitting a safety-related condition report under Sec.  191.23. The 
company stated that because such equipment was already included in the 
definition of ``underground natural storage facility,'' operators might 
incorrectly conclude that two reports were required since the equipment 
was already covered under other provisions of part 191.
    Northern Natural Gas, stated that the definition of a ``modified 
well'' was not clear and could be interpreted to include some minor or 
routine operations, such as the replacement of downhole equipment, 
casing repairs, or tubing changes.
2. PHMSA's Response to Comments Regarding Definitions and Terminology
    PHMSA agrees with the commenters' suggestion to revise the 
definition of ``underground natural gas storage facility,'' and, 
therefore, is amending it in this final rule. The revised definition 
will better articulate the point of demarcation between facilities that 
constitute the UNGSFs and those that are part of other gas pipeline 
facilities. Traditionally, compressor units, buildings, and separators 
have been considered part of the ``topside'' pipe domain and are 
already regulated by other sections of part 192. These components can 
be connected to or from UNGSFs. PHMSA considers a UNGSF to include all 
components up to the valve assembly (and their flanges) that route gas 
at the wellhead to or from the connected pipeline(s). The valve 
assembly may be a single manual or automated valve or a combination of 
valves (e.g., manual and emergency shutdown) and will be located near 
the wellhead.
    With respect to the need for separate definitions for intrastate 
and interstate UNGSFs, PHMSA sees no need for such definitions. The use 
of the phrase ``incidental to natural gas transportation'' in 49 CFR 
192.3 makes clear that the scope of PHMSA's jurisdiction over UNGSFs 
does not depend upon whether a facility is ``interstate'' or 
``intrastate'' but whether it is tied to ``transporting gas,'' as that 
term is defined under 49 U.S.C. 60101(a)(21). This means that UNGSFs 
may include gas storage facilities that can be used occasionally or 
partially for production operations, such as enhanced recovery, gas 
lift, and for production equipment such as power generation and 
powering compressors and pumps.
    Other commenters requested that PHMSA clarify common terms used 
throughout RPs 1170 and 1171, such as ``wellhead,'' ``workover,'' or 
``modified well.'' For similar reasons, the final rule does not provide 
definitions for technical terms generally known to industry, such as 
``wellhead,'' ``modified well,'' and ``workover.'' PHMSA will work with 
operators on a case-by-case basis should the need arise to determine 
the appropriate application of such terminology under the modified 
regulatory text in the final rule.

J. Requests for Additional or More Stringent Requirements

    PHMSA received several comments from private citizens related to 
additional or more stringent requirements for UNGSFs that do not fit 
into the other categories already discussed. Gas Free Seneca, EDF, and 
several private citizens asked PHMSA to require the widespread use of 
subsurface safety valves. Some called for a plan to decommission 
UNGSFs. Others called for a moratorium on new facilities.
    The widespread use of subsurface safety valves may have value but 
would require further study and research as to their effective use at 
each type of UNGSF over other safety enhancements or alternatives. In 
PHMSA's ongoing discussions with operators, the failure rates of 
subsurface safety valves during testing are variable. Additionally, 
once installed, an operator would have to re-open the well to make any 
repairs to the subsurface safety valve, requiring a workover rig to 
retrieve the valve. Given these factors, PHMSA would require additional 
certainty and a strong safety case before promulgating a Federal 
requirement for the widespread use of subsurface safety valves.
    As for a moratorium, PHMSA does not have the authority to site 
UNGSF facilities (and, by extension, to ban new facilities) or to 
abrogate the power of states to issue permits. Therefore, a moratorium 
would be outside the scope of PHMSA's authority and contrary to the 
PIPES Act.
    PHMSA recognizes that there are inherent risks to operating a 
UNGSF; however, Federal and State regulations minimize these risks by 
requiring operators to adhere to clear performance standards designed 
to maintain the integrity of the wellhead and reservoir or cavern. 
Furthermore, the addition of requirements in this final rule related to 
IM and recordkeeping will add greater rigor to the risk-management 
practices than in the IFR. In summary, the IFR and this final rule 
constitute the first large-scale application of PHMSA's regulation 
jurisdiction to UNGSFs. As operators begin applying the RPs and 
assessing the integrity of their facilities and as PHMSA gains 
experience in regulating UNGSFs, the need for any additional 
prescriptive measures will become apparent.

[[Page 8122]]

IV. Rulemaking Analyses and Notices

A. Statutory/Legal Authority for This Rulemaking

    This final rule is published under the authority of the Federal 
Pipeline Safety Law (49 U.S.C. 60101 et seq.), as amended by the PIPES 
Act (Pub. L. 114-183, June 22, 2016). Section 60102 authorizes the 
Secretary of Transportation to issue regulations governing the design, 
installation, inspection, emergency plans and procedures, testing, 
construction, extension, operation, replacement, and maintenance of 
pipeline facilities. The Secretary has delegated her authority in this 
area to the Administrator of PHMSA (49 CFR 1.97). PHMSA is issuing the 
amendments to the requirements for UNGSF involved in pipeline 
transportation under this authority.

B. Executive Order 12866 and DOT Regulatory Policies and Procedures

    This final rule is a significant action under section 3(f) of E.O. 
12866. Therefore, the Office of Management and Budget (OMB) has 
reviewed it.
    PHMSA prepared a regulatory impact analysis (RIA) for the final 
rule, which details the potential for incremental benefits and costs. 
The RIA, which is available in the docket for this final rule, Docket 
No. PHMSA-2016-0016, provides an estimate of the annualized cost 
savings of the final rule and the other alternatives considered 
relative to the baseline. Given the final rule does not impose any 
costs relative to the baseline (IFR), PHMSA determined that the final 
rule is not economically significant under Executive Order 12866 
because the estimated annual impact is less than $100 million.
    Under the final rule, PHMSA expects operators to continue 
performing the same preventative safety measures that they are 
performing under the IFR. Because PHMSA does not expect the final rule 
to change operator safety-related actions, PHMSA does not expect 
changes to the benefits relative to the IFR. Implementation of the IFR 
already achieved benefits that will remain in place, including the 
potential prevention of catastrophic natural gas releases due to the 
failure of storage wells and the associated impacts on human health, 
property, and the environment, including climate change.
    PHMSA does anticipate cost savings once the final rule becomes 
effective. Using the IFR as a baseline, the final rule will reduce 
recordkeeping and reporting burdens, and burdens associated with 
technical evaluations of non-mandatory RPs. The estimated annualized 
cost savings as a result of these changes is $8,452,365 to $12,810,620 
when discounted to present value at 7 percent.

C. Executive Order 13771

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

D. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) of 1980, as amended by the 
Small Business Regulatory Enforcement Fairness Act (SBREFA) of 1996, 
requires Federal agencies to consider the impact of their rules on 
small entities, analyze alternatives that minimize those impacts, and 
make their analyses available for public comments. The Act is concerned 
with three types of small entities: Small businesses, small nonprofits, 
and small government jurisdictions.
    The RFA describes the regulatory flexibility analyses and 
procedures that Federal agencies must complete unless they certify that 
the rule, if promulgated, would not have a significant economic impact 
on a substantial number of small entities. A statement of factual basis 
must support this certification, e.g., by addressing the number of 
small entities affected by the proposed action, calculating expected 
cost impacts on these entities, and evaluating economic impacts.
    PHMSA estimated that this final rule would affect 130 operators. Of 
these 130 operators, there are 14 small entities. However, this final 
rule is a deregulatory action that will reduce the burden of 
information collections. Therefore, PHMSA has determined that this 
final rule will not have a significant economic impact on any small 
entities.

E. Unfunded Mandates Reform Act of 1995

    Title II of the Unfunded Mandates Reform Act (UMRA) of 1995, Public 
Law 104-4, requires that Federal agencies assess the effects of their 
regulatory actions on State, local, and Tribal governments and the 
private sector. Under Section 202 of UMRA, PHMSA must prepare a written 
statement, including a cost-benefit analysis, for proposed and final 
rules with ``Federal mandates'' that might result in expenditures by 
State, local, and Tribal governments, in the aggregate, or by the 
private sector, of $100 million (adjusted annually for inflation) or 
more in any one year (i.e., $153 million in 2016 dollars). This final 
rule will not result in such expenditure. Accordingly, PHMSA is not 
required to provide a written statement in accordance with the UMRA.

F. National Environmental Policy Act

    PHMSA has analyzed this final rule in accordance with section 
102(2)(c) of the National Environmental Policy Act (42 U.S.C. 4332), 
the Council on Environmental Quality regulations (40 CFR 1500-1508), 
and DOT Order 5610.1C. PHMSA has published the results of this analysis 
in an Environmental Assessment (EA) as required by 40 CFR part 1502.
    Based on the EA, PHMSA has determined this final rule would not 
significantly affect the quality of the human environment. To assess 
the impact of these regulations on the human environment, PHMSA 
considered three alternative scenarios, including adopting the IFR 
without amendments, the API RPs as written, and the provisions in this 
final rule. PHMSA concludes that this action will not significantly 
affect the quality of the human environment.
    To the extent that the measures taken to comply with the IFR did 
not involve additional environmental impacts and instead served to 
reduce the risk of natural gas incidents, PHMSA expects this final rule 
to continue these positive environmental impacts. The information in 
this Environmental Assessment report supports a Finding of No 
Significant Impact (FONSI) for this final rule.

G. Executive Order 13132

    E.O. 13132 (``Federalism'') (64 FR 43255, Aug. 10, 1999) requires 
PHMSA to develop an accountable process to ensure ``meaningful and 
timely input by State and local officials in the development of 
regulatory policies that have federalism implications.'' E.O. 13132 
defines policies that have federalism implications to include 
regulations that have ``substantial direct effects on the states, on 
the relationship between the national government and the states, or the 
distribution of power and responsibilities among the various levels of 
government.''
    Section 6 of E.O. 13132 limits regulations that impose substantial 
direct compliance costs on a State unless the Federal government 
provides the funds necessary to pay the direct compliance costs 
incurred by State and local governments. PHMSA also may not issue 
regulations that preempt State law unless the agency consults with 
State and local officials early in the process of developing the 
regulation.
    PHMSA has concluded that this action will not have federalism

[[Page 8123]]

implications because it does not impose any direct compliance costs on 
State or local governments. This final rule reduces the burden from 
information collection and therefore does not impose any direct 
compliance costs.
    With respect to preemption, E.O. 13132 requires agencies to 
determine if their regulatory actions would preempt State law or impose 
a substantial direct cost in compliance on them. Congress explicitly 
addressed the preemption of State underground storage regulations in 
the PIPES Act in section 60141(e). A State authority may adopt 
additional or more stringent safety standards for intrastate 
underground natural gas storage facilities as long as they are 
compatible with Federal requirements. This statement is consistent with 
the existing statute governing PHMSA's preemption of State regulation 
over intrastate pipeline transportation facilities at 49 U.S.C. 
60104(c).
    As noted in the IFR and the discussion above, interstate facilities 
would not be subject to any regulatory safety requirements with respect 
to their wellhead and downhole facilities in the absence of Federal 
action. Even before the issuance of the IFR, the Federal Pipeline 
Safety Laws preempted any State regulation purporting to affect 
interstate pipeline transportation facilities. States with existing 
underground natural gas storage regulations may continue to implement 
those additional, and possibly more stringent, regulations on 
intrastate gas storage facilities to the extent that the State 
regulations are compatible with the new Federal regulations outlined in 
this final rule. Interstate underground storage facilities are now 
subject to the new Federal regulations, whereas previously, those 
facilities were not subject to any regulatory safety requirements.

H. Executive Order 13175

    E.O. 13175 (``Consultation and Coordination with Indian Tribal 
Governments'') reaffirms the Federal Government's commitment to the 
Tribal sovereignty, self-determination, and self-government. To that 
end, the agencies must consult with Tribal governments as they develop 
policy on issues that may affect those communities. This final rule 
imposes no substantial direct compliance costs or burdens on Tribal 
governments. So, the requirements of E.O. 13175 do not apply.

I. Executive Order 13211

    E.O. 13211 (``Actions Concerning Regulations That Significantly 
Affect Energy Supply, Distribution, or Use'') requires Agencies to 
prepare a Statement of Energy Effects when undertaking certain actions. 
Such Statements of Energy Effects shall describe the effects of certain 
regulatory actions on energy supply, distribution, or use, notably: (i) 
Any adverse effects on energy supply, distribution, or use (including a 
shortfall in supply, price increases, and increased use of foreign 
supplies) should the proposal be implemented, and (ii) reasonable 
alternatives to the action with adverse energy effects and the expected 
effects of such alternatives on energy supply, distribution, and use.
    In a memorandum on E.O. 13211, OMB outlines the criteria for 
assessing whether a regulation constitutes a ``significant energy 
action'' and would have a ``significant adverse effect on the supply, 
distribution or use of energy.'' \33\ Of the potentially adverse 
effects on the supply, distribution, relevant to this final rule, only 
one of the criteria is applicable to this final rule: The ability of 
interstate operators to pass costs on to consumers. However, because 
this final rule results in cost savings, it would not increase the cost 
of energy distribution.
---------------------------------------------------------------------------

    \33\ E.O. 13211 was issued May 18, 2002. The Office of 
Management and Budget later released an Implementation Guidance 
memorandum on July 13, 2002.
---------------------------------------------------------------------------

J. National Technology Transfer and Advancement Act of 1995

    The National Technology Transfer and Advancement Act of 1995, 15 
U.S.C. 272, directs Federal agencies to use voluntary consensus 
standards instead of government-written standards when appropriate. The 
OMB Circular A-119, ``Federal Participation in the Development and Use 
of Voluntary Consensus Standards and in Conformity Assessment 
Activities,'' sets the policy for Federal use and development of 
voluntary consensus standards. As defined in OMB Circular A-119, 
voluntary consensus standards are technical standards developed or 
adopted by domestic and international organizations. These 
organizations use agreed-upon procedures to update and revise their 
published standards every three to five years to reflect modern 
technology and best technical practices.
    Accordingly, PHMSA has the responsibility for determining, via 
petitions or otherwise, which standards it should add, update, revise, 
or remove from 49 CFR subchapter D. PHMSA handles these changes to 
incorporate by reference materials via the rulemaking process, which 
allows 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.
    PHMSA worked to make the materials incorporated by reference 
reasonably available to interested parties. PHMSA is prohibited from 
issuing a regulation that incorporates by reference any document unless 
that document is available to the public, free of charge (Pub. L. 113-
30, Aug. 9, 2013).
    To meet these requirements, PHMSA negotiated agreements with all 
but one of the respective standards developing organizations (SDO) with 
standards already incorporated by reference in the PSRs to make 
viewable copies of those standards available to the public at no cost. 
PHMSA has an agreement in place with API, who voluntarily made the RP 
1171 and RP 1170 available on API's public website. API's mailing 
address and the website are listed in 49 CFR part 192.

K. Paperwork Reduction Act

    The Paperwork Reduction Act of 1995 \34\ (PRA), Public Law 104-13, 
is implemented by OMB and requires that agencies submit a supporting 
statement to OMB for any information collection that solicits the same 
data from more than nine parties. The PRA seeks to ensure that Federal 
agencies balance their need to collect information with the paperwork 
burden imposed on the public by the collection.
---------------------------------------------------------------------------

    \34\ Substantially amending the PRA of 1980 (Pub. L. 96-511).
---------------------------------------------------------------------------

    The definition of ``information collection'' includes activities 
required by regulations, such as for permit development, monitoring, 
recordkeeping, and reporting. The term ``burden'' refers to the ``time, 
effort, or financial resources'' the public expends to provide 
information to or for a Federal agency or to fulfill statutory or 
regulatory requirements otherwise. The PRA paperwork burden is measured 
in terms of annual time and financial resources the public devotes to 
meet one-time and recurring information requests.\35\ Information 
collection activities may include:
---------------------------------------------------------------------------

    \35\ 44 U.S.C. 3502(2); 5 CFR 1320.3(b).
---------------------------------------------------------------------------

     Reviewing instructions;
     Using technology to collect, process, and disclose 
information;
     Adjusting existing practices to comply with requirements;
     Searching data sources;
     Completing and reviewing the response; and
     Transmitting or disclosing information.

[[Page 8124]]

    Agencies must provide information to OMB on the parties affected, 
the annual reporting burden, the annualized cost of responding to the 
information collection, and whether the request significantly affects a 
substantial number of small entities. An agency may not conduct or 
sponsor, and a person is not required to respond to, an information 
collection unless it displays a currently valid OMB control number. OMB 
has previously approved the information collection requirements 
contained in IFR under the provisions of the PRA. Since issuing the 
IFR, PHMSA has estimated changes in reporting and recordkeeping burden 
and submitted a revised information collection request to OMB for 
approval. Below is a summary the information collections requested or 
approved for this final rule.
1. Incident Reporting
    PHMSA is finalizing the IFR's revision to 49 CFR 191.15 that 
requires operators to give notice upon the discovery of incidents 
meeting the definition at 49 CFR 191.3. Operators must submit DOT Form 
PHMSA-F7100.2 as soon as practicable but not more than 30 days after 
they detect the event. On August 16, 2017, OMB approved the use of this 
form, ``Incident and Annual Reports for Gas Pipeline Operators,'' under 
Control No. 2137-0522.
2. Safety-Related Conditions Reporting
    PHMSA is finalizing the IFR's revision to Sec.  191.23 that 
requires operators to report a safety-related condition no later than 
ten working days after its discovery. PHMSA estimates it will receive 
four annual responses at an annual burden of 24 hours from each 
operator. This estimate remains unchanged from the IFR's estimate.
    On August 16, 2017, OMB approved this information collection, 
``Reporting Safety-related conditions on Gas, Hazardous Liquid, and 
Carbon Dioxide Pipelines, and Liquefied Natural Gas Facilities,'' under 
Control No. 2137-0578, expiring on August 31, 2019. There is no form 
dedicated to this information collection. Instead, PHMSA will accept 
safety-related condition reports in a variety of formats by mail or 
fax. Instructions for filing are in Sec.  191.25, ``Filing safety-
related condition reports.''
3. Annual Reporting
    PHMSA is finalizing the IFR's amendment to Sec.  191.17, related to 
annual reporting. Operators must submit data Form 7100.4-1, 
``Underground Natural Gas Storage Annual Report,'' no later than every 
March 15. The annual report must include data from the previous 
calendar year. For example, the first annual report was due no later 
than March 15, 2018, and must have included data from the 2017 calendar 
year. OMB approved this information collection, ``Incident and Annual 
Reports for Gas Pipeline Operators,'' on August 16, 2017, under Control 
No. 2137-0522, expiring on August 31, 2020.
    In the IFR, PHMSA estimated a reporting burden of 8 hours to 
complete each annual report form. That estimate included times for 
reviewing instructions, gathering the necessary data, and responding to 
each question. However, PHMSA revised the hourly burden estimate from 8 
hours to 20 hours per response based on public comments, which are 
available for review in Docket No. PHMSA-2016-0016.
4. National Registry of Operators and Notification of Changes
    This information collection consists of two parts. The first part 
requires operators to obtain or validate an Operator Identification 
Number (OPID) from PHMSA. Under the IFR, PHMSA expected to receive 24 
OPID requests and 25 ad hoc notifications. PHMSA estimated that each 
operator would take 1 hour to complete the OPID Assignment form, PHMSA 
F 1000.1. PHMSA is making no changes to these estimates in this final 
rule.
    The IFR revised Sec.  191.22 to require operators to notify PHMSA, 
not less than 60 days prior, of certain events. OMB approved this 
information collection on July 5, 2017, and it will expire on July 31, 
2020. PHMSA estimates that this final rule will result in no additional 
hourly or cost burdens beyond those estimated in the IFR. PHMSA 
estimates the combined annual burden for OPID Assignment and Operator 
Notification at 49 hours. (OMB Control No. 2137-0627).
5. Recordkeeping
    As discussed throughout this rulemaking, operators must create and 
maintain records and in accordance with RP 1170 and RP 1171. Operators 
must also create and maintain written procedure manuals for integrity 
and program operations. Because of these requirements in the IFR, and 
codified in this final rule, 136 entities will be required to keep 
records. PHMSA estimates that it will take operators approximately 1.6 
hours annually to maintain the required records. The cost and hourly 
burden are based on 136 companies with a loaded labor cost of $88 per 
hour. OMB approved this information collection under OMB Control No. 
2137-0634 on October 11, 2018, and it will expire on October 31, 2021. 
No additional collection or recordkeeping requirements would be imposed 
on the public by modifying the requirements of this final rule.

L. Privacy Act

    In accordance with the Privacy Act of 1974, 5 U.S.C. 552(a), anyone 
can search the electronic form of all documents received into any of 
our dockets by the name of the individual submitting the document (or 
signing the document, if submitted on behalf of an association, 
business, labor union, etc.). The complete Privacy Act statement is in 
the Federal Register published on April 11, 2000, (65 FR 19477-78), or 
at the website: https://www.transportation .gov/dot-website-privacy-
policy.

M. Regulation Identifier Number (RIN)

    A regulation identifier number (RIN) is the unique identifier for 
each regulatory action listed in the Unified Agenda of Federal 
Regulations. The Regulatory Information Service Center publishes the 
Unified Agenda in April and October of each year. Use the RIN number to 
find this rulemaking in the Unified Agenda. The RIN number for this 
rulemaking is RIN 2137-AF22.

List of Subjects

49 CFR Part 191

    Underground natural gas storage facility reporting requirements.

49 CFR Part 192

    Definitions, Incorporation by reference, Underground natural gas 
storage facility safety.

49 CFR Part 195

    National Registry of Operators.

    In consideration of the foregoing, PHMSA is amending 49 CFR parts 
191, 192, and 195 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 part 191 continues to read as follows:

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


0
2. In Sec.  191.1, revise paragraph (a) to read as follows:


Sec.  191.1   Scope.

    (a) This part prescribes requirements for the reporting of 
incidents, safety-

[[Page 8125]]

related conditions, annual pipeline summary data, National Registry of 
Operators information, and other miscellaneous conditions by operators 
of underground natural gas storage facilities and natural gas pipeline 
facilities located in the United States or Puerto Rico, including 
underground natural gas storage facilities and pipelines within the 
limits of the Outer Continental Shelf, as that term is defined in the 
Outer Continental Shelf Lands Act (43 U.S.C. 1331).
* * * * *

0
3. In Sec.  191.3, the definitions of ``Incident'' and ``Underground 
natural gas storage facility'' are revised to read as follows:


Sec.  191.3   Definitions.

* * * * *
    Incident means any of the following events:
    (1) An event that involves a release of gas from a pipeline, gas 
from an underground natural gas storage facility (UNGSF), liquefied 
natural gas, liquefied petroleum gas, refrigerant gas, or gas from an 
LNG facility, and that results in one or more of the following 
consequences:
    (i) A death, or personal injury necessitating in-patient 
hospitalization;
    (ii) Estimated property damage of $50,000 or more, including a loss 
to the operator and others, or both, but excluding the cost of gas 
lost; or
    (iii) Unintentional estimated gas loss of three million cubic feet 
or more.
    (2) An event that results in an emergency shutdown of an LNG 
facility or a UNGSF. Activation of an emergency shutdown system for 
reasons other than an actual emergency within the facility does not 
constitute an incident.
    (3) An event that is significant in the judgment of the operator, 
even though it did not meet the criteria of paragraph (1) or (2) of 
this definition.
* * * * *
    Underground natural gas storage facility (UNGSF) means an 
underground natural gas storage facility or UNGSF as defined in Sec.  
192.3 of this chapter.

0
4. In Sec.  191.15, revise paragraphs (c) and (d) to read as follows:


Sec.  191.15   Transmission systems; gathering systems; liquefied 
natural gas facilities; and underground natural gas storage facilities: 
Incident report.

* * * * *
    (c) Underground natural gas storage facility. Each operator of a 
UNGSF must submit DOT Form PHMSA F7100.2 as soon as practicable but not 
more than 30 days after the detection of an incident required to be 
reported under Sec.  191.5.
    (d) Supplemental report. Where additional related information is 
obtained after an operator submits a report under paragraph (a), (b), 
or (c) of this section, the operator must make a supplemental report as 
soon as practicable, with a clear reference by date to the original 
report.

0
5. In Sec.  191.17, revise paragraph (c) to read as follows:


Sec.  191.17   Transmission systems; gathering systems; liquefied 
natural gas facilities; and underground natural gas storage facilities: 
Annual report.

* * * * *
    (c) Underground natural gas storage facility. Each operator of a 
UNGSF must submit an annual report through DOT Form PHMSA 7100.4-1. 
This report must be submitted each year, no later than March 15, for 
the preceding calendar year.

0
6. Revise Sec.  191.22 to read as follows:


Sec.  191.22   National Registry of Operators.

    (a) OPID request. Effective January 1, 2012, each operator of a gas 
pipeline, gas pipeline facility, UNGSF, LNG plant, or LNG facility must 
obtain from PHMSA an Operator Identification Number (OPID). An OPID is 
assigned to an operator for the pipeline, pipeline facility, or 
pipeline system for which the operator has primary responsibility. To 
obtain an OPID, an operator must submit an OPID Assignment Request DOT 
Form PHMSA F 1000.1 through the National Registry of Operators in 
accordance with Sec.  191.7.
    (b) OPID validation. An operator who has already been assigned one 
or more OPIDs by January 1, 2011, must validate the information 
associated with each OPID through the National Registry of Operators at 
https://portal.phmsa .dot.gov, and correct that information as 
necessary, no later than June 30, 2012.
    (c) Changes. Each operator of a gas pipeline, gas pipeline 
facility, UNGSF, LNG plant, or LNG facility must notify PHMSA 
electronically through the National Registry of Operators at https://portal.phmsa.dot.gov of certain events.
    (1) An operator must notify PHMSA of any of the following events 
not later than 60 days before the event occurs:
    (i) Construction of any planned rehabilitation, replacement, 
modification, upgrade, uprate, or update of a facility, other than a 
section of line pipe, that costs $10 million or more. If 60-day notice 
is not feasible because of an emergency, an operator must notify PHMSA 
as soon as practicable;
    (ii) Construction of 10 or more miles of a new pipeline;
    (iii) Construction of a new LNG plant, LNG facility, or UNGSF; or
    (iv) Maintenance of a UNGSF that involves the plugging or 
abandonment of a well, or that requires a workover rig and costs 
$200,000 or more for an individual well, including its wellhead. If 60-
days' notice is not feasible due to an emergency, an operator must 
promptly respond to the emergency and notify PHMSA as soon as 
practicable.
    (2) An operator must notify PHMSA of any of the following events 
not later than 60 days after the event occurs:
    (i) A change in the primary entity responsible (i.e., with an 
assigned OPID) for managing or administering a safety program required 
by this part covering pipeline facilities operated under multiple 
OPIDs;
    (ii) A change in the name of the operator;
    (iii) A change in the entity (e.g., company, municipality) 
responsible for an existing pipeline, pipeline segment, pipeline 
facility, UNGSF, or LNG facility;
    (iv) The acquisition or divestiture of 50 or more miles of a 
pipeline or pipeline system subject to part 192 of this subchapter; or
    (v) The acquisition or divestiture of an existing UNGSF, or an LNG 
plant or LNG facility subject to part 193 of this subchapter.
    (d) Reporting. An operator must use the OPID issued by PHMSA for 
all reporting requirements covered under this subchapter and for 
submissions to the National Pipeline Mapping System.

0
7. Revise Sec.  191.23 to read as follows:


Sec.  191.23   Reporting safety-related conditions.

    (a) Except as provided in paragraph (b) of this section, each 
operator shall report in accordance with Sec.  191.25 the existence of 
any of the following safety-related conditions involving facilities in 
service:
    (1) In the case of a pipeline (other than an LNG facility) that 
operates at a hoop stress of 20% or more of its specified minimum yield 
strength, general corrosion that has reduced the wall thickness to less 
than that required for the maximum allowable operating pressure, and 
localized corrosion pitting to a degree where leakage might result.
    (2) In the case of a UNGSF, general corrosion that has reduced the 
wall thickness of any metal component to less than that required for 
the well's maximum operating pressure, or localized corrosion pitting 
to a degree where leakage might result.
    (3) Unintended movement or abnormal loading by environmental 
causes, such as an earthquake, landslide, or flood, that impairs the 
serviceability of a pipeline or the

[[Page 8126]]

structural integrity or reliability of a UNGSF or LNG facility that 
contains, controls, or processes gas or LNG.
    (4) Any crack or other material defect that impairs the structural 
integrity or reliability of a UNGSF or an LNG facility that contains, 
controls, or processes gas or LNG.
    (5) Any material defect or physical damage that impairs the 
serviceability of a pipeline that operates at a hoop stress of 20% or 
more of its specified minimum yield strength, or the serviceability or 
the structural integrity of a UNGSF.
    (6) Any malfunction or operating error that causes the pressure of 
a pipeline or underground natural gas storage facility or LNG facility 
that contains or processes natural gas or LNG to rise above its maximum 
well operating pressure (or working pressure for LNG facilities) plus 
the margin (build-up) allowed for operation of pressure limiting or 
control devices.
    (7) A leak in a pipeline, UNGSF, or LNG facility containing or 
processing gas or LNG that constitutes an emergency.
    (8) Inner tank leakage, ineffective insulation, or frost heave that 
impairs the structural integrity of an LNG storage tank.
    (9) Any safety-related condition that could lead to an imminent 
hazard and causes (either directly or indirectly by remedial action of 
the operator), for purposes other than abandonment, a 20% or more 
reduction in operating pressure or shutdown of operation of a pipeline, 
UNGSF, or an LNG facility that contains or processes gas or LNG.
    (10) [Reserved]
    (11) Any malfunction or operating error that causes the pressure of 
a UNGSF using a salt cavern for natural gas storage to fall below its 
minimum allowable operating pressure, as defined by the facility's 
State or Federal operating permit or certificate, whichever pressure is 
higher.
    (b) A report is not required for any safety-related condition 
that--
    (1) Exists on a master meter system or a customer-owned service 
line;
    (2) Is an incident or results in an incident before the deadline 
for filing the safety-related condition report;
    (3) Exists on a pipeline (other than an UNGSF or an LNG facility) 
that is more than 220 yards (200 meters) from any building intended for 
human occupancy or outdoor place of assembly, except that reports are 
required for conditions within the right-of-way of an active railroad, 
paved road, street, or highway; or
    (4) Is corrected by repair or replacement in accordance with 
applicable safety standards before the deadline for filing the safety-
related condition report, except that reports are required for 
conditions under paragraph (a)(1) of this section other than localized 
corrosion pitting on an effectively coated and cathodically protected 
pipeline.
    (5) Exists on an UNGSF, where a well or wellhead is isolated, 
allowing the reservoir or cavern and all other components of the 
facility to continue to operate normally and without pressure 
restriction.

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

0
8. The authority citation for part 192 continues to read as follows:

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


0
9. In Sec.  192.3, revise the definition of ``Underground natural gas 
storage facility'' to read as follows:


Sec.  192.3   Definitions.

* * * * *
    Underground natural gas storage facility (UNGSF) means a gas 
pipeline facility that stores natural gas underground incidental to the 
transportation of natural gas, including:
    (1)(i) A depleted hydrocarbon reservoir;
    (ii) An aquifer reservoir; or
    (iii) A solution-mined salt cavern.
    (2) In addition to the reservoir or cavern, a UNGSF includes 
injection, withdrawal, monitoring, and observation wells; wellbores and 
downhole components; wellheads and associated wellhead piping; wing-
valve assemblies that isolate the wellhead from connected piping beyond 
the wing-valve assemblies; and any other equipment, facility, right-of-
way, or building used in the underground storage of natural gas.
* * * * *

0
10. Republished Sec.  192.7(b)(10) and (11) continue to read as 
follows:


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

* * * * *
    (b) * * *
    (10) API Recommended Practice 1170, ``Design and Operation of 
Solution-mined Salt Caverns Used for Natural Gas Storage,'' First 
edition, July 2015 (API RP 1170), IBR approved for Sec.  192.12.
    (11) API Recommended Practice 1171, ``Functional Integrity of 
Natural Gas Storage in Depleted Hydrocarbon Reservoirs and Aquifer 
Reservoirs,'' First edition, September 2015, (API RP 1171), IBR 
approved for Sec.  192.12.
* * * * *

0
11. Revise Sec.  192.12 to read as follows:


Sec.  192.12  Underground natural gas storage facilities.

    Underground natural gas storage facilities (UNGSFs), as defined in 
Sec.  192.3, are not subject to any requirements of this part aside 
from this section.
    (a) Salt cavern UNGSFs. (1) Each UNGSF that uses a solution-mined 
salt cavern for natural gas storage and was constructed after March 13, 
2020, must meet all the provisions of API RP 1170 (incorporated by 
reference, see Sec.  192.7), the provisions of section 8 of API RP 1171 
(incorporated by reference, see Sec.  192.7) that are applicable to the 
physical characteristics and operations of a solution-mined salt cavern 
UNGSF, and paragraphs (c) and (d) of this section prior to commencing 
operations.
    (2) Each UNGSF that uses a solution-mined salt cavern for natural 
gas storage and was constructed between July 18, 2017, and March 13, 
2020, must meet all the provisions of API RP 1170 (incorporated by 
reference, see Sec.  192.7) and paragraph (c) of this section prior to 
commencing operations, and must meet all the provisions of section 8 of 
API RP 1171 (incorporated by reference, see Sec.  192.7) that are 
applicable to the physical characteristics and operations of a 
solution-mined salt cavern UNGSF, and paragraph (d) of this section, by 
March 13, 2021.
    (3) Each UNGSF that uses a solution-mined salt cavern for natural 
gas storage and was constructed on or before July 18, 2017, must meet 
the provisions of API RP 1170 (incorporated by reference, see Sec.  
192.7), sections 9, 10, and 11, and paragraph (c) of this section, by 
January 18, 2018, and must meet all provisions of section 8 of API RP 
1171 (incorporated by reference, see Sec.  192.7) that are applicable 
to the physical characteristics and operations of a solution-mined salt 
cavern UNGSF, and paragraph (d) of this section, by March 13, 2021.
    (b) Depleted hydrocarbon and aquifer reservoir UNGSFs. (1) Each 
UNGSF that uses a depleted hydrocarbon reservoir or an aquifer 
reservoir for natural gas storage and was constructed after July 18, 
2017, must meet all provisions of API RP 1171 (incorporated by 
reference, see Sec.  192.7), and paragraphs (c) and (d) of this 
section, prior to commencing operations.
    (2) Each UNGSF that uses a depleted hydrocarbon reservoir or an 
aquifer reservoir for natural gas storage and was

[[Page 8127]]

constructed on or before July 18, 2017, must meet the provisions of API 
RP 1171 (incorporated by reference, see Sec.  192.7), sections 8, 9, 
10, and 11, and paragraph (c) of this section, by January 18, 2018, and 
must meet all provisions of paragraph (d) of this section by March 13, 
2021.
    (c) Procedural manuals. Each operator of a UNGSF must prepare and 
follow for each facility one or more manuals of written procedures for 
conducting operations, maintenance, and emergency preparedness and 
response activities under paragraphs (a) and (b) of this section. Each 
operator must keep records necessary to administer such procedures and 
review and update these manuals at intervals not exceeding 15 months, 
but at least once each calendar year. Each operator must keep the 
appropriate parts of these manuals accessible at locations where UNGSF 
work is being performed. Each operator must have written procedures in 
place before commencing operations or beginning an activity not yet 
implemented.
    (d) Integrity management program--(1) Integrity management program 
elements. The integrity management program for each UNGSF under this 
paragraph (d) must consist, at a minimum, of a framework developed 
under API RP 1171 (incorporated by reference, see Sec.  192.7), section 
8 (``Risk Management for Gas Storage Operations''), and that also 
describes how relevant decisions will be made and by whom. An operator 
must make continual improvements to the program and its execution. The 
integrity management program must include the following elements:
    (i) A plan for developing and implementing each program element to 
meet the requirements of this section;
    (ii) An outline of the procedures to be developed;
    (iii) The roles and responsibilities of UNGSF staff assigned to 
develop and implement the procedures required by this paragraph (d);
    (iv) A plan for how staff will be trained in awareness and 
application of the procedures required by this paragraph (d);
    (v) Timelines for implementing each program element, including the 
risk analysis and baseline risk assessments; and
    (vi) A plan for how to incorporate information gained from 
experience into the integrity management program on a continuous basis.
    (2) Integrity management baseline risk-assessment intervals. No 
later than March 13, 2024, each UNGSF operator must complete the 
baseline risk assessments of all reservoirs and caverns, and at least 
40% of the baseline risk assessments for each of its UNGSF wells 
(including wellhead assemblies), beginning with the highest-risk wells, 
as identified by the risk analysis process. No later than March 13, 
2027, an operator must complete baseline risk assessments on all its 
wells (including wellhead assemblies). Operators may use prior risk 
assessments for a well as a baseline (or part of the baseline) risk 
assessment in implementing its initial integrity management program, so 
long as the prior assessments meet the requirements of API RP 1171 
(incorporated by reference, see Sec.  192.7), section 8, and continue 
to be relevant and valid for the current operating and environmental 
conditions. When evaluating prior risk-assessment results, operators 
must account for the growth and effects of indicated defects since the 
time the assessment was performed.
    (3) Integrity management re-assessment intervals. The operator must 
determine the appropriate interval for risk assessments under API RP 
1171 (incorporated by reference, see Sec.  192.7), subsection 8.7.1, 
and this paragraph (d) for each reservoir, cavern, and well, using the 
results from earlier assessments and updated risk analyses. The re-
assessment interval for each reservoir, cavern, and well must not 
exceed seven years from the date of the baseline assessment for each 
reservoir, cavern, and well.
    (4) Integrity management procedures and recordkeeping. Each UNGSF 
operator must establish and follow written procedures to carry out its 
integrity management program under API RP 1171 (incorporated by 
reference, see Sec.  192.7), section 8 (``Risk Management for Gas 
Storage Operations''), and this paragraph (d). The operator must also 
maintain, for the useful life of the UNGSF, records that demonstrate 
compliance with the requirements of this paragraph (d). This includes 
records developed and used in support of any identification, 
calculation, amendment, modification, justification, deviation, and 
determination made, and any action taken to implement and evaluate any 
integrity management program element.

PART 195--TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE

0
12. The authority citation for part 195 continues to read as follows:

    Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60116, 
60118, 60132, 60137, and 49 CFR 1.97.


0
13. In Sec.  195.64:
0
a. Revise the section heading;
0
b. Remove ``National Registry of Pipeline and LNG Operators'' and add 
``National Registry of Operators'' in its place everywhere it appears; 
and
0
c. Remove the website address ``https://opsweb.phmsa.dot.gov'' in 
paragraphs (b) and (c) and add ``https://portal.phmsa.dot.gov'' in its 
place.
    The revision reads as follows:


Sec.  195.64  National Registry of Operators.

* * * * *

    Issued in Washington, DC, on January 10, 2020, under authority 
delegated in 49 CFR 1.97.
Howard R. Elliott,
Administrator.
[FR Doc. 2020-00565 Filed 2-11-20; 8:45 am]
 BILLING CODE 4910-60-P