Document ID: PHMSA-2011-0023-0491
Agency: phmsa
Document Type: Rule
Title: Pipeline Safety: Safety of Gas Gathering Pipelines: Extension of Reporting Requirements, Regulation of Large, High-Pressure Lines, and Other Related Amendments
Posted Date: 2021-11-15T05:00Z

[Federal Register Volume 86, Number 217 (Monday, November 15, 2021)]
[Rules and Regulations]
[Pages 63266-63299]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2021-24240]

[[Page 63265]]

Vol. 86

Monday,

No. 217

November 15, 2021

Part III

Department of Transportation

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Pipeline and Hazardous Materials Safety Administration

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49 CFR Parts 191 and 192

Pipeline Safety: Safety of Gas Gathering Pipelines: Extension of 
Reporting Requirements, Regulation of Large, High-Pressure Lines, and 
Other Related Amendments; Final Rule

  Federal Register / Vol. 86, No. 217 / Monday, November 15, 2021 / 
Rules and Regulations  

[[Page 63266]]

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DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous Materials Safety Administration

49 CFR Parts 191 and 192

[Docket No. PHMSA-2011-0023; Amdt. Nos. 191-30; 192-129]
RIN 2137-AF38

Pipeline Safety: Safety of Gas Gathering Pipelines: Extension of 
Reporting Requirements, Regulation of Large, High-Pressure Lines, and 
Other Related Amendments

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

ACTION: Final rule.

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SUMMARY: PHMSA is revising the Federal Pipeline Safety Regulations to 
improve the safety of onshore gas gathering pipelines. This final rule 
addresses Congressional mandates, Government Accountability Office 
recommendations, and public input received as part of the rulemaking 
process. The amendments in this final rule extend reporting 
requirements to all gas gathering operators and apply a set of minimum 
safety requirements to certain gas gathering pipelines with large 
diameters and high operating pressures. The rule does not affect 
offshore gas gathering pipelines.

DATES: The effective date of this final rule is May 16, 2022. The 
Director of the Federal Register approved the incorporation by 
reference of certain material listed in this rule as of April 14, 2006.

FOR FURTHER INFORMATION CONTACT: 
    Technical questions: Steve Nanney, Project Manager, by telephone at 
713-272-2855.
    General information: Sayler Palabrica, Transportation Specialist, 
by telephone at 202-366-0559.

SUPPLEMENTARY INFORMATION:
I. Executive Summary
    A. Purpose of the Regulatory Action
    B. Summary of the Major Provisions of the Regulatory Action
    C. Costs and Benefits
II. Background
    A. Detailed Overview
    B. Advance Notice of Proposed Rulemaking
    C. Pipeline Safety, Regulatory Certainty, and Job Creation Act 
of 2011
    D. Government Accountability Office (GAO) Recommendations
    E. Notice of Proposed Rulemaking
    F. Protecting our Infrastructure of Pipelines and Enhancing 
Safety Act of 2020
III. Analysis of NPRM Comments, GPAC Recommendations, and PHMSA 
Response
    A. Reporting Requirements--Sec. Sec.  191.1, 192.5, 191.17, and 
191.29
    B. Gathering Line Definitions--Sec. Sec.  192.3 and 192.8
    C. Expanded Scope of Gas Gathering Line Regulations--Sec.  192.8
    D. Safety Requirements for Newly Regulated Gas Gathering Lines--
Sec. Sec.  192.9, 192.13, 192.18, 192.452, and 192.619
IV. Section-By-Section Analysis
V. Availability of Standards Incorporated-by-Reference
VI. Regulatory Analysis and Notices

I. Executive Summary

A. Purpose of the Final Rule

    This final rule responds to Government Accountability Office (GAO) 
recommendations and a Congressional mandate by extending existing 
design, operational and maintenance, and reporting requirements under 
the Federal Pipeline Safety Regulations to onshore natural gas 
gathering pipelines (``gathering lines'') in rural areas. Increasingly, 
many of these gathering lines have design and operating parameters that 
are similar to natural gas transmission lines (``transmission lines''), 
which pose an increased risk to public safety and the environment. 
PHMSA expects the regulatory amendments in this final rule will reduce 
the frequency and consequences of failures of onshore gas gathering 
lines and in turn reduce the likelihood of gas-related releases and 
incidents. The requirements in the final rule are designed to prevent 
and detect threats to pipeline integrity, improve public awareness of 
pipeline safety, and improve emergency response to pipeline incidents. 
PHMSA expects this final rule, therefore, will (1) improve public 
safety; (2) reduce threats to the physical environment (including, but 
not limited to, greenhouse gas emissions released during natural gas 
gathering line incidents); and (3) promote environmental justice for 
minority populations, low-income populations, and other underserved and 
disadvantaged communities.
    Gas gathering lines are pipelines used to transport natural gas 
from a current production facility to a transmission line or 
distribution main lines (``main lines''). Generally, these pipelines 
are used to collect unprocessed gas from production facilities for 
transport to a gas treatment plant or other facility. From there, the 
natural gas is separated from petroleum liquids, water, and other 
impurities to prepare the gas for further transportation and sale. In 
the Federal Pipeline Safety Regulations (49 Code of Federal Regulations 
(CFR) parts 190 through 199), gas gathering lines are distinct from gas 
transmission pipelines which are defined in Sec.  192.3 as pipelines 
that: (1) Transport gas from a gathering line or storage facility to a 
distribution center, storage facility, or large volume customer that is 
not downstream from a distribution center; (2) operate at a hoop stress 
of 20 percent or more of specified minimum yield strength (SMYS); \1\ 
or (3) transport gas within a storage field.
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    \1\ SMYS is defined in Sec.  192.3 and refers to the minimum 
force required to deform permanently the material as specified in 
the applicable design codes.
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    Section 192.5 divides gas transmission and gathering lines into 
class locations based on the number of dwellings near the pipeline. 
These range from rural Class 1 to densely populated Class 4 locations. 
Class locations are defined in Sec.  192.5. A Class 1 location is an 
offshore pipeline or an onshore pipeline that has 10 or fewer buildings 
intended for human occupancy within a 1-mile-long class-location unit. 
Unlike transmission lines, which are regulated regardless of location, 
gathering lines in rural Class 1 locations are exempt from Federal 
pipeline safety and reporting regulations in parts 191 and 192. 
However, PHMSA has authority under 49 U.S.C. 60102(a)(2) to issue 
safety regulations for pipeline transportation and pipeline facilities, 
including non-rural gathering lines and rural gathering lines 
designated by the Secretary as ``regulated gathering lines'' under 49 
U.S.C. 60101(a)(21) and (b). Section 60117(b)(2) also authorizes DOT to 
require owners and operators of gathering lines, including rural 
gathering lines that have not been defined as regulated gathering 
lines, to submit information pertinent to its ability to make a 
determination as to whether and to what extent to regulate gathering 
lines.
    Prior to 2005, U.S. gas production had been stagnant since a peak 
in the early 1970s.\2\ The gathering lines that received gas from 
conventional wells typically had smaller diameters than gas 
transmission lines and operated at lower pressures. All else equal, a 
smaller diameter and lower pressure pipeline will release less gas and 
energy during an incident compared with a larger diameter pipeline with 
a greater operating pressure, such as a major transmission line. As a 
result, gathering lines located in Class 1 locations were

[[Page 63267]]

thought to pose relatively low risk to the public and the environment; 
therefore, gathering lines in Class 1 locations were exempt from 
reporting and safety requirements in the Federal Pipeline Safety 
Regulations. On the other hand, to account for the risks related to 
their physical, functional, and operational characteristics, 
transmission pipelines have been subject to PHMSA regulations 
regardless of their location.
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    \2\ See U.S. Energy Information Administration (EIA), ``Natural 
Gas Explained--U.S. natural gas consumption, dry production, and net 
imports, 1950-2019,'' https://www.eia.gov/energyexplained/natural-gas/where-our-natural-gas-comes-from.php (accessed Nov. 3, 2020).
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    Regardless of their size, regulated gathering lines are required to 
comply with safety reporting requirements and minimum safety standards 
in parts 191 and 192. Section 192.8(b) currently provides for two 
categories of regulated onshore gathering lines. Type A gathering lines 
are located in Class 2, Class 3, or Class 4 locations (see Sec.  192.5) 
that operate at relatively higher stress levels. Section 192.9(c) 
subjects Type A regulated gathering lines to the same requirements as 
gas transmission pipelines, with a few exceptions, due to the high 
potential consequences of an incident on a high-stress pipeline in a 
populated area. Type B gathering lines are lower-stress pipelines in 
Class 3, Class 4, and certain Class 2 locations. Section 192.9(d) 
subjects Type B to a less comprehensive set of requirements since such 
pipelines operate at lower stress levels than transmission pipelines. 
As stated above, gathering lines in Class 1 locations are excluded from 
the reporting and safety standards contained in parts 191 and 192. In a 
2006 final rule, PHMSA determined that the potential consequences of a 
release of a smaller-diameter pipeline with a lower maximum allowable 
operating pressure (``MAOP''), in a sparsely populated area, would be 
minimal.\3\
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    \3\ Gas Gathering Line Definition; Alternative Definition for 
Onshore Lines and New Safety Standards, 71 FR 13289, 13291 (Mar. 15, 
2006).
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    Due to new drilling technologies and changing demand factors, 
domestic gas production has been surging since approximately 2006.\4\ 
Besides larger overall production volumes, new drilling technologies 
have also greatly increased the volume of gas that can be extracted 
from a single production site.\5\ As a result, the volume of gas 
transported by gathering lines have also increased significantly. In 
order to transport this additional volume, some gas gathering lines are 
now constructed with large-diameter pipe and operating pressures 
comparable to large, interstate gas transmission pipelines. For 
example, the National Association of State Pipeline Safety 
Representatives (NAPSR) \6\ Resolution 2010-2 AC-2 notes that members 
have observed rural gathering lines as large as 30 inches in diameter 
with a MAOP as high as 1480 psi.\7\ The potential safety and 
environmental consequences of a gas pipeline rupture are proportional 
to the pipeline's diameter and operating pressure. Large diameter 
gathering lines are still exempt from the requirements in parts 191 and 
192 if they are located in Class 1 locations despite their physical and 
functional similarities with transmission pipelines and their increased 
potential for adverse consequences in the event of incident.
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    \4\ EIA, ``U.S. Natural Gas Marketed Production,'' https://www.eia.gov/dnav/ng/hist/n9050us2a.htm. (accessed Nov. 9, 2020).
    \5\ EIA, ``Hydraulically fractured horizontal wells account for 
most new oil and natural gas wells,'' https://www.eia.gov/todayinenergy/detail.php?id=34732 (Jan. 30, 2018).
    \6\ NAPSR is a nonprofit association of State pipeline safety 
officials.
    \7\ Available on the NAPSR website at http://www.napsr.org/resolutions.html.
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    Large diameter, high-pressure gathering lines are susceptible to 
the same types of integrity threats as transmission pipelines, 
including corrosion, excavation damage, and construction defects. The 
exemption of these pipelines from the safety requirements of the 
Federal Pipeline Safety Regulations failed to consider the present 
risks that now exist. In addition, PHMSA has lacked detailed 
information on the safety of gas gathering lines in Class 1 locations 
because such lines have been exempted from requirements to submit 
incident and annual reports under part 191. These reports are necessary 
for PHMSA to analyze how recent changes in the gas production and 
midstream industries affect the functional and operational 
characteristics of unregulated gathering lines, and the safety 
consequences of those changes. While more comprehensive information is 
being collected and analyzed, expanded regulatory measures are needed 
to protect the human and natural environment from the consequences of 
incidents on large-diameter, high-pressure gathering lines from 
preventable causes such as corrosion, excavation damage, and inadequate 
design and construction practices.
    On August 25, 2011, PHMSA issued an advance notice of proposed 
rulemaking (ANPRM) that, among other things, requested comments with 
respect to improving the regulation of gas gathering lines.\8\ 
Following the ANPRM's publication, the Pipeline Safety, Regulatory 
Certainty, and Job Creation Act of 2011 (2011 Pipeline Safety Act, Pub. 
L. 112-90) was enacted on January 3, 2012. Section 21 of the 2011 
Pipeline Safety Act mandated that DOT review existing regulations for 
gathering lines and report to Congress on the sufficiency of existing 
Federal and State laws and the need to modify or revoke existing 
exemptions from Federal regulation for gathering lines.
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    \8\ Pipeline Safety: Safety of Gas Transmission Pipelines, 76 FR 
53086.
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    Subsequently, in 2012, the GAO issued recommendation GAO-12-388 for 
PHMSA to collect data on Federally unregulated hazardous liquid and gas 
gathering lines.\9\ In August 2014, GAO issued recommendation 14-667 
for PHMSA to ``move forward with rulemaking to address gathering 
pipeline safety that addresses the risks of larger-diameter, higher-
pressure gathering pipelines, including subjecting such pipelines to 
emergency response planning requirements that currently do not apply to 
gathering pipelines.'' \10\
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    \9\ GAO, No. 12-388, ``Pipeline Safety: Collecting Data and 
Sharing Information on Federally Unregulated Gathering Pipelines 
Could Help Enhance Safety'' (Mar. 22, 2012).
    \10\ GAO, No. 14-667, ``Oil and Gas Transportation: Department 
of Transportation Is Taking Actions to Address Rail Safety, but 
Additional Actions Are Needed to Improve Pipeline Safety'' at 48 
(Aug. 2014).
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    On April 8, 2016, PHMSA issued a notice of proposed rulemaking 
(NPRM) responding to comments received on the ANPRM and proposing to 
further regulate gas gathering lines to enhance safety.\11\ This final 
rule addresses only those portions of the NPRM dealing with gas 
gathering lines. Portions of the NPRM dealing with gas transmission 
issues have already been implemented in the final rule, ``Pipeline 
Safety: Safety of Gas Transmission Pipelines: MAOP Reconfirmation, 
Expansion of Assessment Requirements, and Other Related Amendments,'' 
(``Gas Transmission Final Rule'') published on October 1, 2019.\12\ The 
remaining gas transmission issues will be addressed in the future in a 
separate rulemaking under the Regulatory Identifier Number (RIN) 2137-
AF39, titled ``Pipeline Safety: Safety of Gas Transmission Pipelines, 
Repair Criteria, Integrity Management Improvements, Cathodic 
Protection, Management of Change, and Other Related Amendments.''
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    \11\ Pipeline Safety: Safety of Gas Transmission and Gathering 
Pipelines, 81 FR 20722.
    \12\ 84 FR 52180.
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    The NPRM discussed the Congressional mandate and GAO 
recommendations, as well as the increased risk factors regarding 
gathering lines discussed above. In addition, the NPRM explained the 
need to clarify the definitions of gas gathering lines in Sec. Sec.  
192.3 and 192.8, which rely on American Petroleum Institute (API) 
Recommended Practice (RP) 80,

[[Page 63268]]

``Guidelines for the Definition of Onshore Gas Gathering Lines,'' first 
edition, April 2000. The current definitions are unclear with respect 
to each of (1) the point at which a non-jurisdictional production 
operation ends and a potentially regulated gas gathering line begins 
and (2) the use of the incidental gathering designation, which allows 
an operator to designate lines downstream from any gathering function 
defined in API RP 80 as a gathering line rather than as a transmission 
line.
    A summary of the proposed changes and PHMSA's response to the 
comments on the NPRM are provided below in section III of this final 
rule.
    On December 28, 2020, the Protecting our Infrastructure of 
Pipelines and Enhancing Safety Act of 2020 (2020 PIPES Act, Pub. L. 
116-260) was enacted. Section 112(a) directed PHMSA to issue a final 
rule in this rulemaking by March 27, 2021.

B. Summary of the Major Provisions of the Final Rule

    This final rule addresses reporting and safety requirements for 
onshore gas gathering lines; offshore gas gathering lines are beyond 
the scope of this rulemaking.\13\ The final rule requires operators of 
all onshore gas gathering lines to report incidents and file annual 
reports under part 191. The purpose of this expanded reporting 
obligation is to gather data about the state of gas gathering 
infrastructure and monitor the safety performance of gas gathering 
lines that were previously exempt from Federal reporting requirements. 
The information in the reports will help determine the need for future 
regulatory changes to address the risks to the public, property, and 
the environment posed by all types of pipeline systems engaged in the 
transportation of gas.
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    \13\ References in this final rule to ``gathering'' therefore 
refer, unless specified otherwise, to onshore gas gathering 
pipelines. Similar to Type A onshore gas gathering lines, offshore 
gas gathering lines are already covered by the requirements in part 
192 applicable to transmission lines, with some exceptions listed in 
Sec.  192.9(b).
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    In addition, the final rule provides for a new Type C regulated 
gathering line \14\ in Sec.  192.8. Type C gathering lines are defined 
as gas gathering lines in Class 1 locations that have outer diameters 
of 8.625 inches or greater and operate at higher stress levels or 
pressures. The safety requirements for Type C lines, referred to as 
Type C requirements in the final rule, are specified in revised Sec.  
192.9(e) and vary based on the outer diameter of the pipeline and the 
potential consequences of a failure. The potential consequences of 
incidents are greater on larger-diameter, higher-pressure pipelines and 
pipelines that are located near buildings intended for human occupancy. 
Type C gathering lines with an outside diameter greater than 16 inches 
and certain other Type C gathering lines that could directly affect 
homes and other structures are required to comply with (1) existing 
requirements for Type B gas gathering lines, and (2) requirements at 
Sec.  192.615 that operators develop and implement emergency plans. 
Type C gathering lines with smaller diameters or that could not 
directly affect homes and other structures have fewer requirements that 
are limited to damage prevention, emergency plans, and public 
awareness. These requirements address known causes of pipeline failures 
including excavation damage, corrosion, and inadequate design and 
construction standards.
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    \14\ This final rule and amended regulatory text use the 
formulation ``Type C'' to identify the newly-regulated onshore 
gathering lines described in the NPRM as ``Type A, Area 2.'' 
However, in discussion of the NPRM and comments thereon, this final 
rule will use the formulation ``Type A, Area 2'' for the convenience 
of the reader.
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C. Costs and Benefits

    Consistent with 49 U.S.C. 60102(b) and Executive Order 12866 
(``Regulatory Planning and Review''),\15\ PHMSA has prepared an 
assessment of the benefits (including safety and environmental 
benefits) and costs of the final rule as well as reasonable 
alternatives. PHMSA expects benefits of the final rule to consist of 
improved safety and avoided environmental harms (including methane 
emissions) from reduction of the frequency and consequences of failures 
of onshore natural gas gathering lines that could result in releases 
and incidents. PHMSA estimates the annualized costs of the rule to be 
approximately $13.7 million per year at a 7-percent discount rate. The 
Regulatory Impact Analysis (RIA) for this final rule is available in 
the docket. The table below provides a summary of the estimated costs 
for the major provisions in this rulemaking and in total (see the RIA 
for further detail on these estimates).
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    \15\ 58 FR 51375 (Oct. 4, 1993).

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                                              Estimated annualized cost
                 Provision                              (7%)
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Right-of-Way Surveillance.................  $170,087.
Corrosion Control.........................  $2,043,260.
Damage Prevention.........................  $285,011.
Public Awareness..........................  $550,464.
Line Markers..............................  $1,680,870.
Emergency Plan............................  $312,167.
Leakage Surveys...........................  $7,626,075.
Incident reporting........................  $134,556.
Annual reporting..........................  $943,408.
Construction..............................  Negligible.
                                           -----------------------------
  Total...................................  $13,745,898.
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II. Background

A. Detailed Overview

Introduction
    The Pipeline Safety Regulations divide gas transmission and 
gathering lines into classes from Class 1 (rural areas) to Class 4 
(densely populated, high-rise areas) that are based on the number of 
buildings or dwellings for human occupancy in the area. Class locations 
are defined in Sec.  192.5. A Class 1 location is an offshore pipeline 
or an onshore pipeline that has 10 or fewer buildings intended for 
human occupancy within a 1-mile-long class-location unit. This final 
rule addresses only onshore gas gathering lines. Gas gathering lines 
located in Class 2, Class 3, and Class 4 locations have been subject to 
reporting requirements in part 191 and safety requirements in part 192. 
Type A lines, which operate at higher pressure, are required to comply 
with most safety requirements applicable to transmission pipelines at 
part 192, while lower-pressure Type B lines are required to follow 
fewer requirements, which are listed in Sec.  192.9(d).
    When PHMSA last issued regulations addressing the safety of gas 
gathering lines in 2006,\16\ it exempted gathering lines in Class 1 
locations from reporting and safety requirements in parts 191 and 192. 
At the time, such pipelines were mostly small-diameter, low-pressure 
pipelines located in sparsely populated, traditional oil-producing 
regions and were thought to pose relatively low risks to the public. 
However, by the time that the 2006 final rule was adopted, innovative 
drilling technologies, new hydrocarbon discoveries, and increasing 
demand for natural gas were starting to transform the industry. Highly 
productive ``unconventional'' drilling techniques have proliferated, 
and modern production sites can be several times more productive than 
conventional wells. The characteristics of the gathering lines 
servicing current wells often have more in common with large interstate 
transmission systems than the diffuse network of small gathering lines 
that predominated when the current gas

[[Page 63269]]

gathering regulatory framework was being developed prior to 2006. These 
changes are placing unprecedented demands and increasing safety risks 
on the Nation's pipeline system.
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    \16\ Gas Gathering Line Definition; Alternative Definition for 
Onshore Lines and New Safety Standards, 71 FR 13289 (Mar. 15, 2006).
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    The final rule requires operators of all onshore gas gathering 
lines to prepare and submit annual reports with information about their 
gas gathering lines and to submit incident reports under part 191. The 
information is necessary to monitor the safety performance of gas 
gathering systems and inform the appropriate level of regulatory 
oversight. This final rule also adopts new safety requirements for 
larger-diameter (i.e., with outer diameters of 8.625 inches or 
greater), higher-operating pressure gas gathering lines to mitigate 
risks to public safety and pipeline integrity. The need to implement 
risk-based protections and build an understanding of the safety of gas 
gathering systems is critical since ``unconventional'' production 
operations continue to expand, often into regions inexperienced with 
oil and gas development--posing new risks to humans and the 
environment.
Natural Gas Gathering Infrastructure Overview
    The U.S. natural gas pipeline network is designed to transport 
natural gas to and from most locations in the country. Approximately 
two-thirds of the lower 48 States depend almost entirely on the 
interstate transmission pipeline system for their supplies of natural 
gas.\17\ In 49 CFR part 192, pipelines are classified into three broad 
groups, based on their function and characteristics: Gathering, 
transmission, and distribution systems. Onshore gathering lines, the 
sole subject of this final rule, typically transport gas from 
production fields to gas transmission pipelines or centralized 
processing and storage facilities. From there, gas is typically 
transported to large industrial users such as gas-fired power stations 
or local distribution companies via transmission pipelines. Finally, 
distribution companies deliver gas to homes and businesses, and other 
end-users. Together, these systems form an interconnected network that 
transports natural gas from the production field to its end users. 
PHMSA estimates that there are over 400,000 miles of onshore gas 
gathering lines throughout the U.S., the vast majority of which are in 
Class 1 locations.\18\
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    \17\ U.S. Department of Energy (DOE), ``Appendix B: Natural 
Gas--Quadrennial Energy Review Report: Energy Transmission, Storage, 
and Distribution Infrastructure'' p. NG-28 (Apr. 2015).
    \18\ API estimated there were 240,000 miles of unregulated 
gathering lines in comments submitted October 23, 2012, available in 
the docket. In order to project an estimate of gathering lines in 
service today, PHMSA adjusted this estimate based on average rate of 
increase in reported mileage of regulated gathering lines from 
operators' annual reports since 2012. See the RIA, available in the 
docket, for additional information on estimates of gathering miles 
affected by the rule.
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Regulatory History
    The Natural Gas Pipeline Safety Act of 1968 (Pub. L. 90-481) vested 
the Secretary with statutory authority to issue regulations to ensure 
the safe transportation of natural gas by pipeline but excluded the 
regulation of gas gathering lines in rural areas, which were defined in 
section 2(3) of the 1968 Act as those locations outside the limits of 
any incorporated or unincorporated city, town, or village, or other 
designated residential or commercial area. Later, Congress modified the 
definition of ``transporting gas'' to provide Secretary the authority 
to designate non-rural areas in order to make pipelines in those non-
rural areas subject to PHMSA's jurisdiction (49 U.S.C. 
60101(a)(21)(B)).
    PHMSA,\19\ through delegation by the Secretary,\20\ and its State 
partners enforce requirements for regulated \21\ gas gathering systems 
in the Federal Pipeline Safety Regulations that are authorized under 49 
U.S.C. 60101 et seq. DOT issued interim minimum Federal safety standard 
regulations for gas pipeline facilities and the transportation of 
natural and other gas by pipeline on November 13, 1968,\22\ and 
subsequently codified broad-based gas pipeline regulations in 49 CFR 
part 192 on August 19, 1970.\23\ The 1970 final rule defined a 
``gathering line'' as ``a pipeline that transports gas from a current 
production facility to a transmission line or main,'' and subjected all 
gathering lines located in non-rural areas (e.g., within the limits of 
any incorporated or unincorporated city, town, or village, or other 
designated residential or commercial area) to all requirements 
applicable to transmission pipelines (Sec. Sec.  192.1 and 192.9).
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    \19\ PHMSA's predecessor agencies include the Research and 
Special Programs Administration (RSPA), the Materials Transportation 
Bureau (MTB), and the Office of Pipeline Safety (OPS). For 
simplicity, all are referred to as DOT in this section.
    \20\ 49 CFR 1.97.
    \21\ Typically, onshore pipelines involved in the 
``transportation of gas,'' see 49 CFR 192.1 and 192.3 for detailed 
applicability.
    \22\ Interim Minimum Federal Safety Standards for the 
Transportation of Natural and Other Gas by Pipeline, 33 FR 16500.
    \23\ Transportation of Natural and Other Gas by Pipeline: 
Minimum Federal Safety Standards, 35 FR 13248.
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    This historical approach to defining PHMSA's jurisdiction, however, 
has left several key gaps which made it difficult to determine where a 
gathering line started and ended. One was that it failed to define 
``current production facility,'' and therefore the point where a non-
jurisdictional production facility became a gathering line was not 
clear.\24\ Additionally, there was no clear definition of where a 
gathering line ended, and a transmission pipeline or distribution main 
line began. The DOT has attempted to clarify these gaps several times. 
In 1974, DOT proposed to revise the definition of a gas ``gathering 
line'' to address this uncertainty as to the beginning and end points 
of gas gathering.\25\ However, the proposal was later withdrawn.\26\
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    \24\ Transportation of Natural and Other Gas by Pipeline: 
Proposed Definition of Gathering Line, 39 FR 34569 (Sept. 26, 1974).
    \25\ Id.
    \26\ Transportation of Natural and Other Gas by Pipeline: 
Withdrawal of Proposed Definition of Gathering Line, 43 FR 42773 
(Sept. 21, 1978).
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    In 1991, DOT again proposed to revise the definition of a gathering 
line following a NAPSR survey of its members noting ongoing 
disagreements about the classification of certain segments of gas 
pipelines.\27\ However, in response to comments on the proposed rule 
and the issuance of the Pipeline Safety Act of 1992 (Pub. L. 102-508), 
PHMSA delayed final action on that proposal to consider additional 
information and the statutory changes. As described earlier, PHMSA was 
previously restricted from issuing regulations for rural gathering 
lines. Section 109 of The Pipeline Safety Act of 1992 expanded DOT's 
authority by authorizing the Secretary to define the term ``regulated 
gathering line,'' and issue safety regulations for the transportation 
of gas through those pipelines despite their location in rural areas 
(49 U.S.C. 60101(b)). The Pipeline Safety Act of 1992 also directed DOT 
to consider functional and operational characteristics in defining 
gathering lines (49 U.S.C. 60101(b)(1)(B)(i)). For the definition of 
the term ``regulated gathering line,'' Congress further directed DOT to 
consider such factors as location, length of line from the well site, 
operating pressure, throughput, and gas composition in deciding which 
gathering lines are functionally gathering yet warrant regulation as 
regulated gathering lines (49 U.S.C. 60101(b)(2)(A)). This authority 
also expressly allowed DOT to depart from the concepts used to define 
gathering for the purposes of determining the scope of the Federal 
Energy Regulatory

[[Page 63270]]

Commission's (FERC) authority under the Natural Gas Act (15 U.S.C. 717 
et seq.) in order to define gas gathering lines based on functional, 
rather than rate-setting, considerations. In other words, whether the 
DOT classifies a pipeline as a transmission line, gathering line, or 
regulated gathering line has no impact on the pipeline's status with 
FERC and vice-versa.
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    \27\ Gas Gathering Line Definition: Notice of Proposed 
Rulemaking, 56 FR 48505 (Sept. 25, 1991).
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    In 1999, PHMSA renewed the effort to define gathering lines. To 
facilitate this project, PHMSA opened a website for public discussion 
on the question of how to define gas gathering lines and whether there 
was a need to subject rural gathering lines to Federal safety 
oversight.\28\ The majority of the comments received focused on the 
work that was being done by API to classify gathering lines. That 
effort culminated in the publication of the first edition of API RP 80 
in April 2000.
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    \28\ Request for Comments: Gas Gathering Line Definition, 64 FR 
12147 (Mar. 11, 1999).
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    The purpose of API RP 80 is to define gas gathering lines in 
onshore areas based on the line's function. It distinguishes a 
gathering function from a ``production operation'' that is not engaged 
in transportation (see section 2.3 of API RP 80) and defines a number 
of points that determine the potential endpoint of the gathering 
function (see section 2.2(a)(1)(A) through (a)(1)(D) of API RP 80), 
such as the inlet to the furthermost downstream gas processing plant or 
the furthermost downstream point where gas produced in the same 
production field or separate production fields is commingled. API RP 80 
defines a gathering line as ``a pipeline, or a connected series of 
pipelines, used to transport gas from the furthermost downstream point 
in a production operation to the furthermost downstream of one of the 
defined endpoints of gathering.'' The document also includes 
supplementary definitions, discussion, and diagrams to provide 
additional guidance on how operators may apply these definitions to 
various types of gathering systems. Section 192.8 includes limitations 
on how aspects of API RP 80 must be applied.
    Ever since API RP 80 was first issued, PHMSA has had concerns about 
``incidental gathering.'' While section 2.2(a)(1)(A) through (a)(1)(D) 
describe points where the gathering function can end, paragraph 
(a)(1)(E) allows an operator to designate pipeline segments that are 
past the furthermost downstream of the other endpoint of gathering up 
to the connection to ``another pipeline'' (typically a transmission 
line) as a gathering line regardless of the actual function or 
operational characteristics of the pipeline itself. This is the 
``incidental gathering'' concept discussed in API RP 80 section 
2.2.1.2.6. By definition, these lines extend beyond the end of any 
gathering functions. When a major gas processing plant or a compressor 
used to raise the pressure for delivery into a transmission line is the 
endpoint, the incidental gathering line segment can be 
indistinguishable from a transmission line in terms of its function, 
diameter, pressure, and gas composition; yet is treated as a gathering 
line rather than a transmission line under part 192. Additionally, 
there are no limits on how far an incidental gathering line may extend 
under the API RP 80 definition. The API RP 80 concept of ``incidental 
gathering'' undermines the functional definition of ``gathering'' that 
API RP 80 was intended to establish. In fact, API RP 80 creates a 
regulatory gap for pipeline segments that bear the least functional and 
operational resemblance to gathering lines.
    In 2003, DOT held public meetings in Austin, Texas, and Anchorage, 
Alaska, to determine the best way to define the terms ``gas gathering 
line'' and ``regulated gathering line'' and what, if any, safety rules 
would be needed for rural regulated gathering lines.\29\ At the 
meetings, DOT proffered a ``sliding corridor'' concept as a possible 
basis for defining which gathering lines should be designated as 
regulated gathering lines. This concept was similar to the ``sliding 
mile'' used for class location determinations, except that the corridor 
would be 1,000 feet long rather than one mile, and the width would vary 
depending on the stress level of the segment of pipe. Wherever the 
corridor contained five or more dwellings, the gathering line segment 
would be subject to a subset of Federal Pipeline Safety Regulations, 
the scope of which would increase as the stress level \30\ of the 
segment increased.
---------------------------------------------------------------------------

    \29\ See 68 FR 62555 (Nov. 5, 2003) (Austin, TX, meeting) and 68 
FR 67129 (Dec. 1, 2003) (Anchorage, AK, meeting). Transcripts for 
the meeting are available for download at regulations.gov under 
Docket No. PHMSA-RSPA-1998-4868.
    \30\ Expressed as the circumferential fore on a pipe (hoop 
stress) produced by the MAOP as a percent of the specified minimum 
yield strength (SMYS). SMYS is defined in Sec.  192.3 and refers to 
the minimum force required to deform permanently the material as 
specified in the applicable design codes.
---------------------------------------------------------------------------

    After these two meetings, DOT published a document that stated that 
the definitions of production and gathering should ensure that Federal 
regulation of gathering lines does not overlap with State regulations 
on production, and should promote consistent application by regulators 
and operators.\31\ The document invited comments on an appropriate 
approach for identifying rural gas gathering lines that warranted 
regulation. After the 2003 public meetings, DOT met several times with 
State agency officials, industry representatives, and others to obtain 
different views on the risks posed by gas gathering lines and the need 
for Federal regulation over the same.
---------------------------------------------------------------------------

    \31\ Gas and Hazardous Liquid Gathering Lines: Clarification of 
Rulemaking Intentions and Extension of Time for Comments, 69 FR 5305 
(Feb. 4, 2004).
---------------------------------------------------------------------------

    In 2006, DOT published a final rule that established the current 
Federal Pipeline Safety Regulations for gas gathering lines in 
Sec. Sec.  192.8 and 192.9.\32\ The final rule incorporated by 
reference API RP 80, which defines ``onshore gas gathering pipelines.'' 
The 2006 final rule also replaced the previous ``non-rural'' criteria 
for designating regulated gathering lines in Sec.  192.9 with a risk-
based approach to regulating gas gathering lines in Class 2, 3, and 4 
locations. In the 2006 final rule, PHMSA chose not to extend any 
reporting or safety requirements to gas gathering lines in Class 1 
locations. At the time, PHMSA noted that such pipelines were typically 
small-diameter, low-pressure lines posing relatively low risks to the 
public. The Federal requirements for gas gathering lines have remained 
in place, mostly unchanged, since 2006.
---------------------------------------------------------------------------

    \32\ Gas Gathering Line Definition; Alternative Definition for 
Onshore Lines and New Safety Standards, 71 FR 13289 (Mar. 15, 2006).
---------------------------------------------------------------------------

Supply Changes
    Between 2005 and 2019, marketed production of natural gas increased 
from 18.9 trillion cubic feet (Tcf) per year to 36.5 Tcf per year.\33\ 
While gross gas production from conventional wells has fallen by 53 
percent from 16.2 Tcf per year to 7.6 Tcf per year between 2005 and 
2019,\34\ overall production has grown due to increased unconventional 
shale gas production. EIA began reporting shale gas well withdrawals in 
2007. In 2007, unconventional shale gas accounted for about 8 percent 
of the total natural gas production in the U.S. Since then, shale gas 
production has increased from 1.9 trillion cubic feet per year to 27.8 
trillion cubic feet per year in 2019 \35\ and now accounts for

[[Page 63271]]

approximately 68 percent of overall gross gas production.
---------------------------------------------------------------------------

    \33\ EIA, ``U.S. Natural Gas Marketed Production,'' https://www.eia.gov/dnav/ng/hist/n9050us2a.htm (accessed Nov. 9, 2020).
    \34\ EIA, ``U.S. Natural Gas Gross Withdrawals from Gas Wells,'' 
https://www.eia.gov/dnav/ng/hist/n9011us2a.htm (accessed Nov. 9, 
2020).
    \35\ EIA, ``U.S. Natural Gas Gross Withdrawals from Shale Gas,'' 
https://www.eia.gov/dnav/ng/hist/ngm_epg0_fgs_nus_mmcfa.htm 
(accessed Nov. 9, 2020).
---------------------------------------------------------------------------

    This increase in unconventional gas extraction has shifted 
production from traditional gas producing regions such as Texas, 
Louisiana, Oklahoma, and the Gulf of Mexico to other areas, such as 
Pennsylvania and Ohio. For instance, in 2001, 5,066,015 million cubic 
feet (MMcf) of natural gas was withdrawn from the Gulf of Mexico, which 
was approximately 21 percent of the Nation's natural gas gross 
production. By 2019, withdrawals decreased to 1,033,922 MMcf. During 
that same period, Pennsylvania's share of production grew from 130,853 
MMcf to 6,896,792 MMcf.\36\ The Department of Energy projects that more 
than half of increases in shale gas production through 2050 will occur 
in the Appalachian Basin (e.g., the Marcellus and Utica Basins), which 
will continue to fuel growth in natural gas production from the 2020 
levels of 33.9 t (Tcf) per year to 43.0 Tcf per year in 2050.\37\
---------------------------------------------------------------------------

    \36\ EIA, ``Gulf of Mexico--Offshore Natural Gas Withdrawals,'' 
https://www.eia.gov/dnav/ng/hist/na1060_r3fmtf_2a.htm (accessed Nov. 
9, 2020); EIA, ``Pennsylvania Natural Gas Gross Withdrawals,'' 
https://www.eia.gov/dnav/ng/hist/n9010pa2a.htm (accessed Nov. 9, 
2020).
    \37\ EIA, ``Annual Energy Outlook 2021'' (Feb. 3, 2021), https://www.eia.gov/outlooks/aeo/production/sub-topic-01.php.
---------------------------------------------------------------------------

Demand Changes
    Increased production of natural gas in the United States has 
depressed average prices and volatility.\38\ In 2004, the growth 
outlook for natural gas production was weak; the EIA forecasted that 
dry gas production would increase by only 1.0 percent annually \39\ and 
that production in the lower 48 would be 21.3 Tcf per year by 2025, or 
up to 25.1 Tcf per year in the rapid technology scenario.\40\ At the 
time, monthly average spot prices at Henry Hub \41\ were high, based on 
historic comparison of prices, fluctuating between $4 per million 
British thermal units (Btu) and $7 per million Btu. Prices rose above 
$11 per million Btu for several months in both 2005 and 2008.\42\ Since 
then, after production shifted to onshore unconventional shale 
resources and price volatility decreased since 2009, natural gas has 
frequently traded between $2 and $4 per million Btu, and the spot price 
has not been above $6 per million Btu for any full month.\43\
---------------------------------------------------------------------------

    \38\ DOE, ``Appendix B: Natural Gas--Quadrennial Energy Review 
Report: Energy Transmission, Storage, and Distribution 
Infrastructure,'' at NG-11 (Apr. 2015), https://www.energy.gov/sites/prod/files/2015/04/f22/QER-ALL%20FINAL_0.pdf.
    \39\ EIA, ``Annual Energy Outlook 2004 With Projections to 
2025,'' at 133 (Jan. 2004), https://www.eia.gov/outlooks/archive/aeo04/pdf/0383(2004).pdf.
    \40\ Id. at 90.
    \41\ Henry Hub is a Louisiana natural gas distribution hub where 
conventional Gulf of Mexico natural gas can be directed to gas 
transmission lines running to different parts of the country. 
Natural gas bought and sold at the Henry Hub serves as the National 
benchmark for U.S. natural gas prices. Id. at NG-29, NG-30.
    \42\ EIA, ``Natural Gas Spot and Futures Prices,'' http://www.eia.gov/dnav/ng/ng_pri_fut_s1_m.htm, (accessed Nov. 9, 2020).
    \43\ Id.
---------------------------------------------------------------------------

    This fall in natural gas prices and volatility was accompanied by 
significant demand growth and changes to the geography of gas demand. 
Low fuel costs, improved gas turbine technology, operational 
advantages, and greenhouse gas concerns have driven a steady growth in 
gas-fired electricity generation. According to the Department of 
Energy, natural gas surpassed coal as the fuel with the highest share 
of net electricity generation in 2016.\44\ Natural gas exports have 
also increased. In 2019, the U.S. exported 4.7 Tcf of gas, over six 
times the amount that was exported in 2006.\45\ Virtually all the gas 
produced and consumed in the U.S. is transported by gas gathering and 
transmission pipelines to distribution pipelines or end-users.
---------------------------------------------------------------------------

    \44\ EIA, ``Electric Power Annual 2019'' Table 3.1.A (Oct. 
2020), https://www.eia.gov/electricity/annual/ (accessed Nov. 9, 
2020).
    \45\ EIA, ``U.S. Natural Gas Exports,'' https://www.eia.gov/dnav/ng/hist/n9130us2a.htm (accessed November 9, 2020).
---------------------------------------------------------------------------

Consequences for Gas Gathering
    Modern production techniques, higher production volumes, and the 
geography of new gas discoveries have had consequences for gas 
gathering systems that PHMSA did not contemplate in 2006. Individual 
unconventional wells can be several times more productive than 
conventional facilities, and multiple wells can be drilled from a 
single wellpad, resulting in a large increase in the volume of gas that 
can flow from production and gathering lines serving a single site. In 
addition, these productivity gains have led to a surge in production 
overall, which expands the demands placed on the overall gas gathering 
pipeline network. Modern gas gathering lines often bear a closer 
resemblance to large interstate transmission lines than the diffuse 
network of small, low-pressure lines that previously characterized 
gathering lines. An incident on such pipelines can have serious 
consequences, even in a Class 1 location.
    Although PHMSA has not collected annual report information on the 
mileage or diameter of gas gathering lines in Class 1 locations, 
various stakeholders have reported significant growth in large-
diameter, high-pressure gas gathering lines operating outside the scope 
of the Federal Pipeline Safety Regulations. NAPSR noted in the preamble 
to its Resolution 2010-2 AC-2 that ``it is not uncommon to find rural 
gas gathering pipelines up to 30 inches in diameter and operating at a 
MAOP of 1480 psi [pounds per square inch, or approximately 1495 pounds 
per square inch gauge (psig)]'' in modern gas gathering systems,\46\ 
which resembles the operational characteristics of major interstate 
transmission pipelines that are subject to part 191 and 192 regardless 
of where they are located. Similarly, the GAO noted that 24-inch 
diameter unregulated gathering lines were located and constructed in 
close proximity to homes in Pennsylvania, and 30 to 36-inch diameter 
unregulated gas gathering lines were planned for construction in the 
Eagle Ford shale formation in Texas.\47\ In comments to the NPRM, the 
Pennsylvania Public Utility Commission noted that producers in the 
State are constructing gas gathering lines as large as 36 inches in 
diameter with operating pressures up to 1480 psig.
---------------------------------------------------------------------------

    \46\ NAPSR, Resolution 2010-2AC-2 (Sept. 30, 2010), http://nebula.wsimg.com/215b293abe58ff21d6d2ad867ae864a3?AccessKeyId=8C483A6DA79FB79FC7FA&disposition=0&alloworigin=1.
    \47\ GAO, No. 14-667 at 24.
---------------------------------------------------------------------------

    The energy that can be released in a pipeline explosion or fire is 
proportional to a pipeline's throughput capacity. The potential impact 
radius formula in Sec.  192.903, which calculates the radius of a 
circle within which the potential failure of a pipeline could have a 
significant impact on people or property, increases proportionally with 
pressure and exponentially with the diameter of the pipeline. An 
incident on any large-diameter, high-pressure natural gas pipeline can 
have potentially catastrophic consequences, regardless of whether it is 
defined as a transmission or gathering line, and even in sparsely 
populated Class 1 locations. For example, one of the deadliest gas 
transmission pipeline incidents in U.S. history occurred in a Class 1 
location when a 30-inch transmission line operated at 675 psig ruptured 
near Carlsbad, New Mexico, on August 19, 2000.\48\ In that incident, 
internal

[[Page 63272]]

corrosion led to an explosion that killed 12 individuals who had been 
camping 675 feet from the rupture site. Following this incident, PHMSA 
added Sec.  192.476 requiring operators to incorporate measures to 
mitigate internal corrosion threats in the design and construction of 
new transmission lines--however, that requirement does not affect 
gathering lines that may have a similar risk profile. In another 
incident on December 11, 2012, a 20-inch transmission line with a MAOP 
of 1000 psig ruptured in Sissonville, West Virginia, due to corrosion 
caused when the protective pipe coating was damaged by rocky backfill 
during installation. While there were no serious injuries in that 
incident, three houses and several hundred feet of road surface were 
destroyed, and Interstate 77 was shut down for 19 hours.\49\ The fire 
melted a portion of the interstate highway, prompting one local 
official to describe the highway as looking ``like lava, just 
boiling.'' \50\
---------------------------------------------------------------------------

    \48\ National Transportation Safety Board (NTSB), NTSB/PAR-03/
01, ``Pipeline Incident Report: Natural Gas Pipeline Rupture and 
Fire Near Carlsbad, New Mexico'' (Feb. 2003), https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR0301.pdf.
    \49\ NTSB, NTSB/PAR-14/01, ``Accident Report: Columbia Gas 
Transmission Corporation Pipeline Rupture Sissonville, West 
Virginia'' (Feb. 2014), https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR1401.pdf.
    \50\ Brinks, Travis, ``Remembering the Sissonville Pipeline 
Explosion.'' WV Metro News. Dec. 11, 2023, https://wvmetronews.com/2013/12/11/remembering-the-sissonville-pipeline-explosion/ (accessed 
June 15, 2021).
---------------------------------------------------------------------------

    Although PHMSA has not historically collected incident reports for 
gas gathering lines in Class 1 locations, such gathering lines are 
subject to incidents of similar magnitude and consequence as gas 
transmission pipelines with comparable physical and operating 
characteristics. For example, on November 14, 2008, a 20-inch gas 
gathering line exploded in Grady County, Oklahoma, which injured two 
people, destroyed three homes, and shut down a nearby highway.\51\ On 
June 8, 2010, a bulldozer struck a 14-inch gas gathering line in 
Darrouzett, Texas, causing an explosion that killed two workers and 
injured three others, including one worker who was critically injured 
and required medical evacuation by helicopter.\52\ On June 29, 2010, 
three men working on a 24-inch gas gathering line in Grady County, 
Oklahoma, were injured when it exploded; one worker was airlifted to a 
nearby hospital with burns covering half of his body.\53\ On August 1, 
2018, a six-inch gas gathering line failed in Midland, Texas, which 
caused a nearby 12-inch transmission line to also explode, killing one 
worker and injuring seven others.\54\ A few days later, on August 9, 
2018, corrosion on a 10-inch gas gathering line resulted in another 
explosion in Midland, killing a three-year-old girl and badly burning 
three others. Fatal incidents on smaller lines such as the first 
Midland, Texas, incident described above and an explosion caused by an 
improperly abandoned 2-inch production line connected to a gas well in 
Firestone, Colorado,\55\ underscore the need to collect information on 
the risks posed by smaller diameter lines. Even non-fatal incidents can 
result in significant damage to infrastructure and property, lead to 
evacuations, disrupt gas service, or otherwise harm the public, 
property, or the environment.
---------------------------------------------------------------------------

    \51\ Griswold, Jennifer and Sargent, Brian. ``Natural Gas 
Pipeline Explosion Destroys Homes Near Alex.'' The Oklahoman, Nov. 
14, 2008, www.oklahoman.com/article/3321932/natural-gas-pipeline-explosion-destroys-homes-near-alex (accessed Feb. 12, 2021).
    \52\ The Associated Press. ``Two Killed in Texas Panhandle Gas 
Line Explosion.'' Arkansas Democrat Gazette, June 8, 2010, 
www.arkansasonline.com/news/2010/jun/08/2-killed-texas-panhandle-gas-line-explosion/ (accessed Feb. 12, 2021).
    \53\ Pittman, Jerry. ``Pipeline Explosion West of Pocasset 
Injures Three, One Seriously.'' The Oklahoman, June 29, 2010, 
www.oklahoman.com/article/3472182/pipeline-explosion-west-of-pocasset-injures-three-one-seriously, (accessed Feb. 12, 2021).
    \54\ Lee, Mike, and Soraghan, Mike. ``Deadly Pipelines, No 
Rules.'' E&E News, Mar. 4, 2019, www.eenews.net/special_reports/EEnews_highlights/stories/1060123021, (accessed Feb. 12, 2021).
    \55\ NTSB, NTSB/PAB-19/02, ``Pipeline Accident Brief Natural Gas 
Explosion at Family Residence Firestone, Colorado'' (Oct. 2019), 
https://www.ntsb.gov/investigations/AccidentReports/Reports/PAB1902.pdf.
---------------------------------------------------------------------------

    These hazards may be further exacerbated by the changing geography 
of U.S. gas production, which was noted by the GAO in their March 2012 
report, ``Collecting Data and Sharing Information on Federally 
Unregulated Gathering Pipelines Could Help Enhance Safety.'' Incidents 
involving new gas production fields may overwhelm the capabilities of 
local first responders in rural areas who may lack experience and the 
resources to respond adequately to serious incidents associated with 
intensive gas production and processing operations, including high-
pressure pipelines.
Regulatory Gaps
    PHMSA estimates that there are over 400,000 miles of unregulated 
onshore gathering lines. For comparison, operators reported 320,000 
miles of gas transmission lines in 2019. As demonstrated above, even 
though some gathering lines share the same physical, functional, and 
operational characteristics and potential adverse consequences from an 
incident as transmission lines, they are exempt from reporting 
requirements in part 191 and minimum safety standards in part 192.
    The final rule closes this gap by requiring all gas gathering 
facilities to submit incident reports and annual reports under part 
191. In addition, the final rule adopts minimum safety standards for 
larger gas gathering lines that operate at higher pressures to help to 
ensure that operators address the critical risks that these previously 
unregulated facilities pose to pipeline integrity and public safety 
such as corrosion, excavation damage, and inadequate emergency response 
planning.

B. Advance Notice of Proposed Rulemaking

    On August 25, 2011, PHMSA published an ANPRM, soliciting public 
comments regarding the revision of the Pipeline Safety Regulations 
applicable to the safety of both gas gathering and gas transmission 
pipelines.\56\ PHMSA requested comments regarding 15 topic areas 
covering gathering and transmission lines.
---------------------------------------------------------------------------

    \56\ Pipeline Safety: Safety of Gas Transmission Pipelines, 76 
FR 53086.
---------------------------------------------------------------------------

    The specific issues related to gas gathering included whether 
regulatory exemptions for filing incident, annual, and safety-related 
condition reports should be repealed. In addition, PHMSA requested 
comment on a proposal to repeal the incorporation by reference of API 
RP 80 into the Pipeline Safety Regulations and replace it with a new 
definition of gathering lines in part 192 for determining the beginning 
and end points of gas gathering lines. Adoption of a new definition 
would address defining endpoints for non-jurisdictional gas production 
operations and setting limits for the ``incidental gathering'' concept 
in API RP 80. PHMSA also requested comment on expanding the definition 
of the term ``regulated onshore gas gathering pipelines'' to include a 
new category of high-pressure, large diameter gathering lines in Class 
1 Locations.
    PHMSA received 103 comments to the ANPRM. Based on these comments, 
PHMSA developed proposals for some of those topics in an NPRM published 
on April 8, 2016 (NPRM), which is the basis for this final rule.

C. Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011

    Section 21 of the 2011 Pipeline Safety Act mandated that DOT review 
its existing regulations for gas gathering lines and report to Congress 
on the sufficiency of existing Federal and State laws to ensure the 
safety of gas

[[Page 63273]]

gathering lines; the economic impacts, the technical practicability, 
and challenges of applying existing Federal regulations to unregulated 
gathering lines; and the need to modify or revoke existing exemptions 
from Federal regulation for gathering lines, subject to a risk-based 
assessment. PHMSA sent the required report to Congress on May 8, 
2015.\57\ The report identified issues with the difficulty of 
designated gathering lines in complex systems due to missing, 
ambiguous, or circular definitions of terms used to determine the start 
and end points of gathering lines, and used to describe state-level 
regulation of gathering lines. The report also observed that, with few 
exceptions, State regulators had not imposed design, construction, 
operation, and maintenance requirements for gathering lines beyond 
existing Federal requirements for Type A and Type B regulated gathering 
lines. The report also notes that most of the States which had 
established requirements for gathering lines other than Federally 
regulated Type A and Type B gathering lines had not adopted 
prescriptive safety standards or performance standards with well-
defined authorized acceptance criteria. The report informs this 
rulemaking.
---------------------------------------------------------------------------

    \57\ PHMSA, Report to Congress: Natural Gas and Hazardous Liquid 
Gathering Lines (May 2015), https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/report_to_congress_on_gathering_lines_0.pdf.
---------------------------------------------------------------------------

D. Government Accountability Office (GAO) Recommendations

    The GAO issued GAO-12-388 in March 2012, which recommended PHMSA 
collect data on Federally unregulated hazardous liquid and gas 
gathering lines comparable to the data collected from operators of 
regulated gathering lines. The GAO suggested that the purpose of such 
data collection would be to assess the safety risks posed by 
unregulated gathering lines. GAO also noted that States and operators 
could use this information to share effective safety practices and 
lessons learned. In August 2014, the GAO issued a report, GAO-14-667, 
which further recommended that PHMSA initiate a rulemaking to address 
gathering line safety that would focus on the risks presented by 
larger-diameter, higher-pressure gathering lines, including a 
requirement that such pipelines meet emergency planning 
requirements.\58\
---------------------------------------------------------------------------

    \58\ On September 29, 2015, GAO prepared a statement, GAO-15-
843T (``Department of Transportation Needs to Complete Regulatory, 
Data, and Guidance Efforts'') reiterating the need for PHMSA to 
complete its regulatory efforts based on GAO's previous 
recommendations.
---------------------------------------------------------------------------

E. Notice of Proposed Rulemaking

    On April 8, 2016, PHMSA published the NPRM, which proposed new 
pipeline safety requirements and revisions of existing requirements in 
16 major topic areas.
    To manage the breadth of the topics raised in the NPRM, PHMSA 
separated the topics into three final rules. The first of final rule 
addressed the gas transmission mandates in the 2011 Pipeline Safety 
Act; a final rule was published in this rulemaking on October 1, 
2019.\59\ That final rule addresses comments received concerning the 
scope of the proposed gas transmission requirements for existing Type A 
and Type B regulated gathering lines. The second final rule is this 
one, which addresses only the portions of the NPRM affecting the safety 
of gas gathering lines, particularly reporting requirements for all gas 
gathering lines and additional requirements for Type C regulated 
gathering lines. The remaining gas transmission pipeline concerns are 
being considered in a third final rule (under Regulatory Identification 
Number 2137-AF39) that is under development.
---------------------------------------------------------------------------

    \59\ Pipeline Safety: Safety of Gas Transmission Pipelines: MAOP 
Reconfirmation, Expansion of Assessment Requirements, and Other 
Related Amendments, 84 FR 52180.
---------------------------------------------------------------------------

    With respect to the current rulemaking, the NPRM contained 
proposals to:
    (1) Extend part 191 requirements for incident reports, annual 
reports, and safety-related condition reports to all gas gathering 
lines;
    (2) repeal the incorporation by reference of API RP 80 and revise 
the regulatory definitions for determining if a pipeline is a gathering 
line;
    (3) expand the scope of regulated gathering lines to include a new 
category of ``Type A, Area 2'' for gathering lines in Class 1 locations 
with a diameter of 8 inches or greater and operating at high pressure; 
and
    (4) require newly regulated Type A, Area 2 gathering lines to 
comply with the existing requirements in Sec.  192.9 for Type B 
gathering lines, plus an additional requirement for establishing 
emergency plans per Sec.  192.615.
    Pursuant to 49 U.S.C. 60115(c), PHMSA shared the proposed standards 
on gathering lines with the Gas Pipeline Advisory Committee (GPAC) 
after initially considering the comments to the NPRM.\60\ The GPAC met 
on June 25-26, 2019, to consider the proposed standards regarding 
gathering lines. Subsequently, PHMSA posted the meeting slides that 
were used for the GPAC votes as well as the transcript, which 
constitute the statutorily required report of the GPAC's 
recommendations, including minority views.\61\
---------------------------------------------------------------------------

    \60\ The Technical Pipeline Safety Standards Committee, or GPAC, 
is an advisory committee, created pursuant to 49 U.S.C. 60115, that 
advises PHMSA on proposed safety standards, risk assessments, and 
safety policies for natural gas pipelines. The GPAC was established 
under the Federal Advisory Committee Act (Pub. L. 92-463) and 
section 60115 of the Federal Pipeline Safety Law (49 U.S.C. 60101 et 
seq.). The GPAC consists of 15 members, with membership divided 
among Federal and State agencies, the regulated industry, and the 
public. The GPAC considers the ``technical feasibility, 
reasonableness, cost-effectiveness, and practicability'' of each 
proposed pipeline safety standard and provide PHMSA with recommended 
actions pertaining to those proposals.
    \61\ https://primis.phmsa.dot.gov/meetings/MtgHome.mtg?mtg=143.
---------------------------------------------------------------------------

    A summary of the four pertinent NPRM proposals, comments received 
on these proposals, the GPAC recommendations, and PHMSA's responses to 
the comments are provided in section III below.

F. Protecting Our Infrastructure of Pipelines and Enhancing Safety Act 
of 2020

    The 2020 PIPES Act was enacted on December 28, 2020. Section 112(a) 
directed PHMSA to issue a final rule in this rulemaking by the March 
27, 2021.

III. Summary of the NPRM Comments, and GPAC Recommendations, and PHMSA 
Responses

    The comment period for the NPRM ended on July 7, 2016, after being 
extended for one month. PHMSA received over 400 comments from groups 
representing the regulated pipeline industry; groups representing 
public interests, including environmental organizations; State utility 
commissions and regulators; members of Congress; individual pipeline 
operators; and private citizens. PHMSA received several comments after 
the July 7, 2016 deadline. Consistent with Sec. Sec.  5.13(i)(5) and 
190.323, PHMSA considered those late-filed comments considering 
commenters' interest in the rulemaking and the absence of additional 
expense or delay resulting from their consideration.
    Pursuant to 49 U.S.C. 60115(e), the GPAC met on June 25 and 26, 
2019 to consider the topics related to the safety of gas gathering 
lines in the NPRM. The GPAC came to consensus decisions and voted on 
recommended changes to the NPRM elements that would make those 
regulatory amendments more technically feasible, reasonable, cost-
effective, and practicable. These recommendations are documented in

[[Page 63274]]

the transcript of the meeting and summarized in the vote slides.\62\
---------------------------------------------------------------------------

    \62\ See https://primis.phmsa.dot.gov/meetings/MtgHome.mtg?mtg=143.
---------------------------------------------------------------------------

A. Reporting Requirements--Sec. Sec.  191.1, 191.15, 191.17, 191.23, 
and 191.29

1. Summary of PHMSA's Proposal
    Existing Sec.  191.1(b)(4)(ii) exempts all onshore gas gathering 
lines other than regulated gathering lines (as specified in accordance 
with Sec.  192.8) from all reporting requirements of part 191.
    The NPRM proposed to repeal the exemption in Sec.  191.1(b)(4) for 
gas gathering lines that are not regulated under Sec.  192.8. However, 
the NPRM would continue to exempt previously unregulated gathering 
lines from Operator Identification Number (OPID) validation 
requirements in Sec.  191.22(b) and National Pipeline Mapping System 
(NPMS) requirements in Sec.  191.29. Therefore, all gas gathering 
lines, including previously unregulated gathering lines, would be 
required to comply with annual and incident reporting requirements in 
Sec. Sec.  191.15, 191.17, and 191.25. This proposal was intended to 
provide new information on the extent, configuration, and safety 
performance of previously unregulated gas gathering lines.
    The proposed rule would have required submission of OPID requests, 
incident reports, and safety-related condition requests beginning on 
the effective date of a final rule. Annual reports would have been due 
on March 15 of the calendar year after the effective date of a final 
rule.
2. Summary of Public Comments
    Several citizen and public safety, and environmental groups, 
including the Pipeline Safety Trust (PST), the Wisconsin Safe Energy 
Alliance, NAPSR, the Coalition to Reroute Nexus, Earthworks, and the 
Environmental Defense Fund (EDF), supported the proposed provisions to 
remove the exemption for filing reports by operators of unregulated gas 
gathering lines. NAPSR agreed that extending reporting requirements to 
``unregulated'' gathering lines would help determine if current 
operation and maintenance practices pose a risk to public safety and if 
additional requirements are required but suggested that PHMSA consider 
limiting certain requirements that could pose an unnecessary burden, 
such as detailed leak reporting information in part M of the gas 
transmission and gas gathering annual report form (DOT Form PHMSA F 
7100.2-1). Some public commenters emphasized that available data on 
unregulated facilities could be inaccurate or outdated, particularly in 
areas where gas development has grown rapidly. Some of these groups 
also encouraged PHMSA to require gas gathering operators to submit 
geospatial pipeline location data for the NPMS, citing the usefulness 
of NPMS data for determining the need for future regulation.
    Trade associations and pipeline industry entities provided a 
variety of responses to the proposed reporting requirements, ranging 
from full support, including for NPMS reporting, to total opposition to 
all proposed reporting requirements. The Independent Petroleum 
Association of America (IPAA) and other commenters representing oil and 
gas producers opposed changes to the scope of part 191 and commented 
that PHMSA has no statutory authority to apply reporting requirements 
to production lines and gathering lines that are not regulated 
gathering lines determined pursuant to Sec.  192.8.
    Several trade association and pipeline industry commenters 
including API, GPA Midstream (formerly the Gas Processors Association) 
and IPAA, expressed concern that the proposed reporting requirements 
could have significant cost impacts for operators that were not 
commensurate with the risk posed by the majority of those lines. 
Industry commenters also commented that it is not feasible to collect 
the information necessary to complete the proposed annual report by the 
reporting deadline of March 15 as required by Sec.  191.17 on top of 
the efforts necessary to identify Type A, Area 2 (or Type C) regulated 
gas gathering lines within six months of the effective date the rule 
(see section III.C. below).
    Industry commenters were especially concerned about reporting 
requirements for pipeline attributes that were related to requirements 
that did not apply to unregulated gas gathering lines. For example, 
GPA, API, and other industry commenters argued that the reporting of 
safety-related conditions (Sec.  191.23), including MAOP exceedances, 
would require information on MAOP, corrosion monitoring, and SMYS that 
were not otherwise required for previously unregulated gathering lines. 
The current forms for submitting gas transmission and gathering 
incident reports (F 7100.2) and annual reports (F 7100.2-1) also refer 
to regulations or records not required for unregulated gas gathering 
operators. These commenters recommended that PHMSA create separate 
incident and annual report forms for gathering lines that would collect 
information relevant to gas gathering lines that are not subject to 
part 192 and eliminate the proposed requirement to report safety-
related conditions.
    GPA Midstream commented that they supported PHMSA's goal of 
collecting necessary information on gas gathering lines, but that an 
abbreviated annual report form was necessary to avoid unnecessary 
costs. GPA Midstream further commented that unregulated gas gathering 
lines should be excepted from the OPID validation and change 
notification requirements in Sec.  191.22(b) and (c).
3. GPAC Recommendations
    Following discussion in the June 2019 meetings, the GPAC voted 12-0 
that the proposed requirement that operators of newly regulated gas 
gathering lines file annual and incident reports pursuant to part 191 
was technically feasible, reasonable, cost-effective, and practicable, 
if the following changes are made:
     Add specificity to location (e.g., latitude and longitude 
coordinates) and cause information to the incident report form;
     Make sure all appropriate current annual report data 
elements are incorporated in the annual report form for currently 
unregulated gathering lines, including decade of installation;
     Address the possibility of unknown data;
     Implement a phase-in period of at least 24 months for 
unregulated gathering annual reports; and
     Consider additional comments from members submitted to the 
meeting docket (PHMSA-2016-0136), specifically, position papers from 
API/GPA Midstream and PST submitted in response to the GPAC meeting 
notice, and comments submitted after the GPAC meeting by each of GPA 
Midstream and the United Association of Journeymen and Apprentices of 
the Plumbing and Pipe Fitting Industry of the United States and Canada, 
AFL-CIO.
    The GPAC agreed that the proposed reporting requirements were 
needed to support future oversight, but recommended changes on the 
details of implementation. PHMSA explained that it intended to create a 
new annual report form for gas gathering lines that are not subject to 
safety requirements in part 192 (reporting regulated gathering lines) 
separate from the existing DOT Form PHMSA 7100.2-1 required for 
operators of gas transmission and regulated gas gathering lines. This 
form would exclude information that is not relevant or applicable to 
operators of pipeline systems that are not required to comply with part 
192.

[[Page 63275]]

    The GPAC recommended extending the compliance deadline for annual 
reports to 24 months after publication in the Federal Register to grant 
additional time for operators to identify newly regulated gathering 
lines and collect the necessary information. However, the GPAC agreed 
that incident reports should begin to be filed on the effective date of 
the rule since the data required to submit an incident report should be 
readily obtainable when an incident occurs.
4. PHMSA Response
    PHMSA disagrees with comments that it lacks the statutory authority 
to require reports from operators of gathering lines other than 
currently regulated gathering lines as determined under Sec.  192.8. 
Section 60117(b) of Federal Pipeline Safety Law specifically authorizes 
the Secretary to ``require owners and operators of gathering lines to 
provide the Secretary information pertinent to the Secretary's ability 
to make a determination as to whether and to what extent to regulate 
gathering lines.'' Congress made no distinction between ``gathering 
lines'' and ``regulated gathering lines'' for reporting purposes. This 
information-gathering process is precisely what the NPRM proposed--to 
gather information on all gathering lines that would enable PHMSA to 
make informed judgments about the need for, and scope, of potential 
regulation. Congress intended that the Secretary have the authority to 
request information from operators of unregulated gathering lines in 
order to help determine ``what additional gathering lines should be 
regulated.'' \63\ PHMSA seeks to obtain information regarding current 
risks to people, property, and the environment due to unregulated rural 
gathering lines to determine whether rural gathering lines are 
presenting unacceptable risk that would warrant additional regulations. 
The information contained in annual and incident reports submitted by 
operators under part 191 would reasonably help achieve this objective.
---------------------------------------------------------------------------

    \63\ S. Rep. 104-334, section 12 (104th Cong., 2nd Sess. 1996).
---------------------------------------------------------------------------

    In addition to the plain meaning of section 60117, Congress has 
articulated its intent for DOT to obtain information about the risks of 
rural gathering lines. In 1992, when Congress granted DOT authority to 
define gathering lines and regulated gathering lines for purposes of 
safety regulations, it recognized that some rural gathering lines might 
present unacceptable risks and authorized DOT to regulate lines whose 
risk warranted regulation. In its report on H.R. 1489, a bill leading 
to the Pipeline Safety Act of 1992, the House Committee on Energy and 
Commerce instructed DOT to ``find out whether any gathering lines 
present a risk to people or the environment, and if so, how large a 
risk and what measures should be taken to mitigate the risk.'' \64\ The 
Committee reasoned that ``DOT had been attempting to define gathering 
lines for years. Anecdotal evidence indicates that there may be 
pipelines that are called gathering lines but that may really be 
transmission lines, and that there may be gathering lines that because 
of size or other physical characteristics should be regulated.'' \65\ 
Although Congress did not require DOT to regulate gathering lines, it 
expected DOT to obtain the necessary information to determine whether 
risks exist to warrant regulation, as further evidenced by the House 
report: ``DOT is given a great deal of discretion to implement this 
section based on the information it receives as it proceeds. If DOT 
finds that none of these lines poses a hazard to people, property, or 
the environment, none of them will be regulated.'' \66\
---------------------------------------------------------------------------

    \64\ H.R. Report No. 102-247(1), at 2653 (102nd Cong., 1st Sess. 
(1991)).
    \65\ Id.
    \66\ Id. Additionally, 49 U.S.C. 60101(b)(2)(A) specifically 
requires the Secretary, when defining ``regulated gathering line,'' 
to consider factors as location, length of line from the well site, 
operating pressure, throughput, and the composition of the 
transported gas to determine which lines are functionally gathering 
and should be regulated because of their physical characteristics. 
It reasonably follows, as evident in the Congressional record, that 
Congress intended that Secretary could obtain such information from 
operators in order to consider such factors.
---------------------------------------------------------------------------

    The final rule fulfills the Congressional mandate by requiring 
operators of all onshore gas gathering lines to file incident and 
annual reports under part 191. This includes pipelines that are not 
currently designated as Type A or Type B regulated gathering lines nor 
newly designated as Type C gathering lines as a result of the final 
rule. For clarity, this final rule designates these reporting-regulated 
lines as ``Type R'' gathering lines that are subject to reporting under 
part 191 but are not designated as regulated gathering lines in part 
192. These requirements are necessary to evaluate the safety risks on 
gas gathering systems and determine what, if any, additional measures 
may be warranted to reduce those risks. As demonstrated above, it is no 
longer reasonable to assume rural gas gathering lines pose uniformly 
low risk. Information on the changing functional and operational 
characteristics of gas gathering lines and their safety performance is 
necessary for PHMSA to better understand the consequences of these 
changes and to set requirements for gathering lines in the future. 
Extension of incident and annual reporting to these additional gas 
gathering lines will provide PHMSA information needed for identifying--
and promulgating regulatory requirements or pursuing enforcement 
activity--design, manufacture, installation, and operational/
maintenance issues common to particular pipeline characteristics or 
operators.
    Congress also understood that the community around gathering lines 
can change and authorized DOT to consider these changes when regulating 
gathering lines. In its report that accompanied Senate Bill 1166, the 
bill that became the Natural Gas Pipeline Safety Act of 1968, the 
Committee on Interstate and Foreign Commerce recognized that the 
population in an area can change, and that the statute authorized DOT 
to define from time to time what is a non-rural area.\67\ The Committee 
emphasized that a ``populated area'' means not only an area with a 
large number of people but also areas where pipeline rights-of-way are 
near houses, schools, and places of employment.\68\
---------------------------------------------------------------------------

    \67\ H.R. Rep. 90-1390, at 3234 (90th Cong., 2nd Sess. 1968).
    \68\ See id.
---------------------------------------------------------------------------

    However, PHMSA recognizes that some reporting requirements 
applicable to gas transmission and regulated gathering lines may not be 
necessary for gas gathering lines that are not currently subject to 
part 192. In particular, PHMSA is not requiring operators who are not 
required to establish an MAOP under part 192 to comply with 
requirements to report MAOP exceedances and other safety-related 
condition reports. In addition, in consideration of the comments, PHMSA 
is withdrawing the proposed requirement for gas gathering line 
operators that are not subject to part 192 to file safety-related 
condition reports required by Sec.  191.23. Similarly, the final rule 
exempts gas gathering lines that are not subject to part 192 from the 
OPID validation and construction notification requirements in Sec.  
191.22(b) and (c) because such pipelines are not subject to the 
construction requirements in part 192.
    While all gathering lines are now required to submit incident and 
annual reports, PHMSA is ensuring that the required data is applicable 
and relevant to operators of Type R gathering lines that are not 
subject to part 192. In consideration of comments on the NPRM and in 
the GPAC recommendations, PHMSA has

[[Page 63276]]

developed a new annual report form and a new incident report form for 
operators of gas gathering lines that are not subject to part 192 with 
more limited information that is appropriate for such facilities. For 
example, with regard to annual reports, PHMSA has developed an 
abbreviated annual report form incorporating information specifically 
relevant to gas gathering lines that are not currently regulated under 
part 192, including the decade of installation, if known. New forms and 
instructions are available in the public docket and will be made 
available on PHMSA's website at https://www.phmsa.dot.gov/forms/operator-reports-submitted-phmsa-forms-and-instructions.
    The new annual report and incident report forms for Type R 
gathering lines address the GPAC's recommendations, including:
     Requiring incident location information that is equivalent 
to what is required for regulated gas gathering lines;
     Annual report fields appropriate for identifying and 
evaluating public safety and environmental risks that may be associated 
with unregulated gas gathering lines, including:
    [cir] Miles by decade of installation,
    [cir] Miles by pipeline diameter,
    [cir] Miles by pipe material and corrosion protection status, and
    [cir] Number of leaks repaired or scheduled for repair.
     On the Type R annual report form, allow reporting of an 
unknown decade of installation.
     On the Type R incident report form, allow reporting of an 
unknown date of installation and certain fields related to pipeline 
material properties and damage prevention investigations.
    In the final rule, operators of previously unregulated gas 
gathering lines must begin submitting annual reports beginning with the 
first annual report cycle occurring after the endpoints of Type C or 
Type R gathering lines have been determined one year after the 
publication date of the final rule. As a result, operators of Type R 
and Type C gathering lines must submit a 2022 annual report no later 
than March 15, 2023. March 15 is the existing deadline for submitting 
annual reports for other gas pipeline facilities, consistent reporting 
deadlines reduces confusion and administrative burdens on PHMSA and 
operators with both Type R and regulated gas pipeline facilities. This 
compliance deadline represents a phase-in period well in excess of a 
year as measured from the publication date of the final rule.
    This compliance deadline is approximately 6 months shorter than 
recommended by the GPAC. However, PHMSA believes that prompt submission 
of such reports is necessary for PHMSA's timely evaluation of whether 
additional regulatory efforts are needed to manage the safety and 
environmental risks associated with Types C and R gathering lines. 
PHMSA's limited information on these lines inhibits the robust 
understanding of their environmental and public safety risks needed to 
determine whether additional requirements are also warranted. The 
longer the delay in obtaining that information, the longer before PHMSA 
can diagnose and respond to a need for additional public safety and 
environmental protections from previously-unregulated gas gathering 
lines. PHMSA therefore does not believe an [18 month] compliance 
timeline would be overly burdensome on affected operators when 
evaluated against those potential safety benefits. The simplified form 
for Type R lines includes provisions for ``unknown'' fields to minimize 
burdens on gathering line operators to complete. While the Type C form 
is more extensive, such lines are also more likely to be more modern 
shale gas systems installed within the last 10-15 years. PHMSA expects 
the use of electronic recordkeeping and geospatial information systems 
is more widespread among such operators compared with traditional 
gathering systems and therefore expects that completing Type C annual 
reports will not be overly burdensome on affected entities. Finally, 
PHMSA notes that the compliance timeline is consistent with the 
approach taken in historical expansions of pipeline reporting 
requirements. For example, in the final rule titled, ``Pipeline Safety: 
Safety of Hazardous Liquid Pipelines,'' \69\ PHMSA required affected 
operators to submit annual reports the first year after the effective 
date.
---------------------------------------------------------------------------

    \69\ 84 FR 52260 (Oct. 1, 2019).
---------------------------------------------------------------------------

    For similar reasons, the final rule does not include provisions for 
operators to request a delayed compliance deadline for the annual 
report requirement similar to those included in Sec. Sec.  192.8 and 
192.9. Additionally, most of the records necessary to prepare an annual 
report are also necessary in order to define the endpoints of regulated 
gas gathering. Operators should therefore begin collecting the 
necessary information immediately in order to ensure they are able to 
submit a complete annual report on or before the deadline in the final 
rule.

B. Gathering Line Definitions--Sec. Sec.  192.3 and 192.8

1. Summary of PHMSA's Proposal
    PHMSA proposed to revise 49 CFR part 192 to clarify the definition 
of gathering lines in order to address confusion regarding how the 
endpoints of gathering and production are currently determined. The 
existing definition of gathering lines relies on language in API RP 80. 
In practice, however, operators and inspectors have had difficulty 
consistently applying the definitions that are used to define the start 
and endpoints of gathering in API RP 80 given the complexities in the 
configuration of gathering line systems in midstream operations. In 
addition, Federal and State enforcement of the current requirements has 
been hampered by the use of API RP 80, a complex standard that can 
produce multiple classifications for the same pipeline system. 
Specifically, API RP 80 defines certain processes and equipment that 
may constitute a ``production operation'' but does not include defined 
endpoints of the production function in section 2.3 like it does for 
gathering in section 2.2.
    This issue was raised in comments by NAPSR and others, who 
suggested simplifying the definition of a gas gathering line and 
setting clear, restrictive limits on where non-jurisdictional 
production operation ends and gas gathering begins. NAPSR commented in 
response to the ANPRM that State regulators had ``many difficulties in 
applying the definitions contained in API RP 80'' and recommended a 
simpler definition for the term gathering line. NAPSR recommended 
defining the end of production at the wellhead or first metering point 
downstream of the well. As described in the regulatory history section, 
PHMSA also had concerns with how the ``incidental gathering'' concept 
has been used to classify pipelines that perform gas transmission 
functions as gathering lines subject to less stringent requirements 
intended for small, low-pressure, traditional gathering lines.
    In lieu of relying on API RP 80's definition of gathering line, the 
NPRM proposed new stand-alone definitions for ``onshore production 
facility/operation'', ``gas processing plant,'' ``gas treatment 
facility'', and ``gathering line (onshore)'' to determine the beginning 
and endpoints of each gathering line. The proposed definitions were 
found in Sec.  192.3 of the NPRM and the application of those 
definitions was included in Sec.  192.8. PHMSA proposed to define the 
end of onshore production operations as the furthermost downstream 
point

[[Page 63277]]

where measurement for the purposes of calculating minerals severance 
occurs or there is a comingling of the flow stream from two or more 
wells.
    The NPRM also would have required operators to request approval 
from the Associate Administrator of Pipeline Safety in order to extend 
gathering beyond the furthermost upstream gas processing plant. 
Finally, in order to address PHMSA's concerns with the lack of definite 
limits on the application of incidental gathering, PHMSA proposed 
limiting the distance that a gathering line could continue beyond a 
defined endpoint of gathering to 1 mile, provided that it does not 
cross a highway or railroad right of way.
2. Summary of Public Comments
    NAPSR, the Pennsylvania Public Utility Commission (PAPUC), PST, 
EDF, and a member of the public all expressed support for elimination 
of API RP 80, citing the confusion that exists in the present document 
for defining the endpoints of gas production and processing facilities 
and gas gathering lines. Some of these commenters had concerns or 
suggested clarifications about specific issues. For example, NAPSR and 
other State pipeline safety officials suggested PHMSA clarify that 
authority to approve extending gathering beyond the first downstream 
natural gas processing plant (Sec.  192.8(a)(2)) or to use the point of 
comingling on fields greater than 50 miles apart (Sec.  192.8(a)(3)) 
resides with State pipeline safety agencies in addition to the PHMSA 
Associate Administrator for Pipeline Safety. The PAPUC commented that 
PHMSA should remove the point of gas comingling (the location where gas 
from two or more production sites join for further transportation 
downstream) from the proposed definition of an onshore production 
operation due to concerns that operators could use that concept to 
classify relatively large pipelines that are performing a gathering 
function as non-jurisdictional production lines.
    API, The American Gas Association (AGA), IPAA, GPA Midstream, the 
Marcellus Shale Coalition, the Oklahoma Oil and Gas Association 
(OKOGA), the Domestic Energy Producers Alliance, and several individual 
pipeline operators commented that API RP 80 adequately delineated 
production and gathering lines on a functional basis and should not be 
eliminated from part 192. Most signaled that they would be open to 
collaboration to improve some definitional issues, especially via 
changes to API RP 80 through the collaborative API standards-revision 
process. To this end, API suggested initiating a revision of API RP 80 
instead of using the proposed wording in the NPRM. Other industry 
groups and operators, such as the Virginia Oil and Gas Association and 
the Plastic Pipe Institute, opposed any modification to the current 
definitions and usage of API RP 80; these commenters contended that 
changing the start point of gathering would violate PHMSA's statutory 
limitation on regulating production lines, that State agencies 
adequately regulate intrastate production and gathering lines, or that 
PHMSA had not provided sufficient safety evidence to support changes to 
the definition of gathering.
    Industry commenters also raised a number of specific concerns 
regarding the replacement definitions proposed by PHMSA. The most 
substantive comments concerned potentially ambiguous language in 
PHMSA's proposed definitions for ``onshore production facility or 
onshore production operation'' and ``gathering line (onshore).'' API 
opposed the proposed definitions but suggested edits that it claimed 
would provide more specificity to the types of processes that could be 
considered production functions. API also suggested clarifications on 
how points of comingling are treated in the definitions of the 
endpoints of gathering and production and make other changes. Other 
commenters requested clarification that the proposed definitions of gas 
processing plants and gas treatment plants did not apply to facilities 
on gas transmission or distribution lines. Many industry commenters 
requested a standalone definition of ``farm taps'' to clarify the 
regulatory requirements applicable to service lines connected to 
production, gathering, and transmission lines.
    Many commenters opposed PHMSA's proposal to limit the use of the 
``incidental gathering'' designation to one mile from the furthermost 
downstream point of gathering. API proposed a standalone definition of 
``incidental gathering'' consistent with the current definition in API 
RP 80 and suggested that if PHMSA is concerned about particular lines 
abusing the definition of incidental gathering, then it should 
designate such incidental gathering lines as regulated gathering lines 
rather than generally restrict the use of the incidental gathering 
designation in API RP 80. It further suggested that the proposed Type 
A, Area 2 (now Type C) requirements could address safety concerns with 
large-diameter, high-pressure incidental gathering lines. API further 
commented that requiring operators to redesignate previously 
unregulated incidental gathering lines as transmission lines would 
result in significant costs, especially if the proposed gas 
transmission requirements in the NPRM applied to them. GPA Midstream 
commented that the ``proposed limitation of one mile is too 
restrictive,'' and that reclassifying existing gathering lines as 
transmission lines would result in substantial compliance costs that 
need to be addressed in the RIA. However, GPA Midstream and the OKOGA 
suggested that a 10-mile limit was a reasonable compromise that would 
establishes a definite limit on incidental gathering but with enough 
flexibility to accommodate different system configurations.
    Industry commenters also contended that the implementation 
timeframe for identifying and reclassifying pipelines as regulated 
gathering lines (6 months) was too short.
3. GPAC Recommendation
    The GPAC voted 11-0, with one abstention, that the proposed rule 
was technically feasible, reasonable, cost-effective, and practicable, 
if the proposed new and revised definitions related to gas gathering in 
Sec.  192.3 and the proposed changes to Sec.  192.8(a) for determining 
beginning and endpoints of gathering were withdrawn. PHMSA noted during 
the meeting that it will monitor the outcome of the working group 
preparing a second edition of API RP 80 and a new document, API RP 
1182, ``Safety Provisions for Large Diameter Rural Gas Gathering 
Lines,'' and consider whether those efforts merit potential changes to 
the definition of gas gathering lines in a future rulemaking. Although 
the GPAC discussion acknowledged PHMSA's concerns regarding the 
``incidental gathering'' concept in API RP 80, the GPAC did not discuss 
or recommend any particular mileage limitation on that concept. 
Likewise, the GPAC did not make any specific recommendations regarding 
the terms ``onshore production facility/operation'', ``gas processing 
plant'', ``gas treatment facility'', or ``gathering line (onshore)''.
4. PHMSA Response
    PHMSA agrees with the majority of commenters and the GPAC that 
definitions of ``gas processing plant,'' ``gas treatment facility,'' 
and ``gathering line (onshore)'' should be omitted from the final rule. 
After the NPRM was published, API established two committees (API RP 
1182 and API RP 80) to consider revisions to API RP 80 to address the 
same ambiguities in those

[[Page 63278]]

definitions that the NPRM was intended to address. Both documents have 
since published. The final rule does not repeal the use of the existing 
definition of gathering line based on API RP 80 (1st edition, 2000) and 
Sec.  192.8. PHMSA will consider updating the definitions associated 
with defining gathering and production lines in a separate rulemaking 
after evaluating the second edition of API RP 80, Definition of Onshore 
Gas Gathering Lines and new API RP 1182, Safety Provisions for Large 
Diameter Rural Gas Gathering Lines. PHMSA declines to adopt in this 
rulemaking API RP 1182 or the 2nd edition of API RP 80 in their 
entirety without providing the public an opportunity to review and 
comment upon those standards. A few aspects of API RP 1182 have been 
adapted in the final rule, these are described in section III.C. of the 
preamble of this final rule.
    However, due to safety and enforcement concerns, the final rule 
defines limits to ``incidental gathering'' on new, replaced, relocated, 
or otherwise changed gathering lines. The final rule changes the NPRM's 
proposed one-mile endpoint for the designation ``incidental 
gathering,'' but does impose a clear and defined limitation of ten 
miles on ``incidental gathering'' for any such pipelines constructed 
after the effective date of this rulemaking. Therefore, for gathering 
lines installed after the effective date of the rule, the ``connection 
to another pipeline'' endpoint in section 2.2(a)(1)(E) of API RP 80 may 
not be used if the connection is ten or more miles from the endpoints 
of gathering defined in paragraphs (a)(1)(A) through (a)(1)(D). In 
other words, if an ``incidental gathering'' portion of a newly 
constructed pipeline would be ten or more miles in length, then the 
incidental gathering concept may not be used and the gathering line 
terminates at the furthermost downstream endpoint defined in API RP 80 
sections 2.2(a)(1)(A) through (a)(1)(d), subject to the limitations in 
Sec.  192.8. While PHMSA appreciates the contribution of the API RP 80 
committee on these definitional issues, ``incidental gathering'' 
concept is a significant source of uncertainty and concern that 
requires an immediate regulatory remedy to protect public safety. This 
limitation in the final rule immediately improves regulatory certainty 
regarding each of the endpoints of gathering and prevents potential 
abuse of the incidental gathering concept pending PHMSA's consideration 
of the second edition of API RP 80 and operational experience gained 
from implementation of the definitional changes in this final rule.
    The purpose of API RP 80 was to define clear endpoints to the 
gathering and production lines based on their function and purpose and 
eliminate the circular definitions in part 192 at the time. While the 
definitions for the end of gathering in section 2.2(a)(1)(A) through 
(a)(1)(D) of API RP 80 are not perfect, they provide some definite 
limits that are reasonably based on the function of the line in 
question. However, the incidental gathering concept negates both goals 
by allowing gathering to continue past what API itself defines as the 
end of gathering functions to the ``connection to another pipeline.'' 
This reintroduces the circular definitions in the original definition 
in Sec.  192.3 that adoption of API RP 80 was intended to clarify. API 
RP 80 includes no limits to how far downstream the connection to 
another pipeline can be. As a result, PHMSA has observed supposedly 
incidental gathering lines that extend for several miles.
    In addition to adding ambiguity to the regulations, unlimited 
application of incidental gathering creates a regulatory gap where 
long-distance pipelines that are functionally and operationally 
indistinguishable from transmission lines are classified as gathering 
lines with less stringent safety standards. By definition, an 
incidental gathering line is downstream of the last gathering function 
described in section 2.2 of API RP 80. Past that point the gas will not 
undergo further gathering-related processing or comingling. Incidental 
gathering can also include piping downstream of a major gas processing 
plant or a compressor used to increase downstream pressure so that the 
gas can be delivered to a transmission line (see section 2.2.1.2.4 of 
API RP 80); if that is the case, then the incidental gathering line is 
being operated at the same (high) pressure as the transmission line to 
which it is directly connected. In other words, such lines have 
functional and operational characteristics--including potential 
consequences--consistent with gas transmission lines, not production or 
gathering facilities. While some allowance to connect to nearby 
transmission facilities could be appropriate on economic or 
practicability grounds, this justification fades the further downstream 
it is applied.
    In order to reduce this regulatory gap for gathering lines that are 
downstream of the last gathering function, the final rule limits 
incidental gathering to no more than 10 miles from the furthermost 
downstream endpoint of gathering for new, replaced, relocated, or 
otherwise changed pipelines. Specifically, PHMSA no longer allows the 
use of the ``connection to another pipeline'' endpoint in paragraph 
2.2(a)(1)(E) of API RP 80 if it is 10 or more miles downstream of the 
furthermost of the other endpoints defined in paragraphs 2.2(a)(1)(A) 
through (a)(1)(D) of API RP 80. An ``incidental gathering'' pipeline 
installed after the effective date of the rule that extends beyond 10 
miles shall be considered a transmission line, starting from the non-
incidental endpoint of gathering defined in API RP 80. PHMSA currently 
uses a similar distance-based limit in Sec.  192.8(a)(3) to set 
reasonable parameters for using the point of comingling, an actual gas 
gathering function, described in API RP 80 section 2.2(a)(1)(C) as an 
endpoint to gathering. While existing gathering lines are not affected 
by this change, such pipelines may be designated as Type C regulated 
gas gathering and subject to safety requirements, depending on their 
diameter, pressure, and operating environment (see sections III.C and 
III.D below).
    Applying these limits on incidental gathering solely to only new, 
replaced, relocated, or otherwise changed gathering lines and revising 
the limit from 1 mile to 10 miles addresses the concerns raised by 
comments from operators while establishing a limit to incidental 
gathering going forward. Applicability to only new and replaced 
pipelines avoids disruption associated with reclassifying previously 
unregulated existing gathering lines as transmission lines and reduces 
the overall cost of the final rule for existing infrastructure. PHMSA 
recognizes that comments from operators broadly opposed the proposed 1-
mile limit, and the GPAC did not recommend revisions to definition, 
including incidental gathering. However, as an alternative, a 10-mile 
limit was supported in public comments from GPA Midstream and OKOGA, 
trade associations for gas gathering line operators, and represents a 
reasonable first step towards establishing a firm endpoint to 
gathering. PHMSA also notes that a 10-mile limit on the ``incidental 
gathering'' concept would also be consistent with previous 
interpretation letters issued by PHMSA.\70\ Extending the limit on 
incidental gathering to 10 miles provides greater flexibility for 
siting processing facilities and associated

[[Page 63279]]

pipelines compared with the 1-mile limit in the proposed rule, 
addressing concerns raised in comments. PHMSA also notes that during 
this rulemaking process, there was support among both gathering line 
operators and public commenters to clarify the application of 
incidental gathering lines and impose common-sense limitations on the 
``incidental gathering'' concept. Finally, as noted in the summary of 
comments, GPA Midstream and OKOGA submitted comments open to a 10-mile 
limit to incidental gathering rather than 1 mile as proposed in the 
NPRM.
---------------------------------------------------------------------------

    \70\ See, e.g., PHMSA, Interpretation Letter No. PI-08-0010, 
Letter to State of Colorado Public Utilities Commission (Feb. 20, 
2009) (endorsing use of ``incidental gathering'' concept for an 8-
mile line), https://cms7.phmsa.dot.gov/sites/phmsa.dot.gov/files/legacy/interpretations/Interpretation%20Files/Pipeline/2009/PI-09-0006.pdf.
---------------------------------------------------------------------------

    Although the second edition of API RP 80 includes a 20-mile 
limitation to incidental gathering, PHMSA does not believe that newly 
constructed ``incidental gathering'' lines should be permitted to 
extend that far from a gathering facility. As explained in the NPRM, 
PHMSA has for more than a decade expressed concerns that the 
``incidental gathering'' concept has been used to allow pipelines with 
certain characteristics (operating pressures, capacity, etc.)--and, 
consequently, risks to the public and the environment--resembling gas 
transmission lines to avoid part 192 regulatory requirements governing 
those lines. PHMSA does not, therefore, understand the 20-mile limit 
contemplated by API RP 80 to be as effective in capturing the safety 
and environmental benefits in comparison to what a more demanding 
mileage limitation would realize.
    Further, PHMSA's discussion with various stakeholders revealed that 
there are very few incidental gathering lines that extend beyond 10 
miles from the gathering facility; PHMSA is not aware of any, proposed 
new pipeline construction projects that would be classified as 
incidental gathering and extend 10 miles from the end of the gathering 
facility. The 10-mile limitation on incidental gathering, therefore, 
provides regulatory certainty to stakeholders, recognizes uncertainty 
regarding the cost impacts that could arise if incidental gathering is 
limited to 1 mile and on existing gas gathering lines, as proposed, and 
ensures that the regulatory gap that currently exists with regard to 
API RP 80's absence of a limitation on incidental gathering is closed 
for all newly constructed lines. PHMSA acknowledges that a regulatory 
gap remains for existing incidental gathering lines and new and 
replaced incidental gathering lines 10 miles or shorter. However, both 
new and existing incidental gathering lines with the highest potential 
safety hazards are either covered by existing safety standards for Type 
A and Type B regulated gas gathering lines in Class 2, Class 3, and 
Class 4 locations, or the new safety standards for Type C regulated gas 
gathering lines in Class 1 locations established by this final rule. 
These requirements are described in sections III.C and III.D. of the 
preamble to this final rule. PHMSA will reconsider the issue of 
definitions, including the endpoint of production and treatment of 
incidental gathering lines, in a separate rulemaking in order to ensure 
stakeholders are able to comprehensively comment on newly proposed 
definitions and the second edition of API RP 80. Infrastructure and 
incident data collected as a result of this rulemaking, inspection 
data, and the public comment process will help inform future limits to 
incidental gathering.

C. Expanded Scope of Gas Gathering Line Regulations--Sec.  192.8

1. Summary of PHMSA's Proposal
    In the NPRM, PHMSA proposed to create a new category of Type A 
regulated gas gathering lines in Class 1 locations that had a nominal 
diameter of 8 inches (actual outside diameter of 8.625 inches) or 
greater. This new category of regulated gathering lines was identified 
in the table of the proposed Sec.  192.8 as ``Type A, Area 2'' (in the 
final rule it is referred to as Type C), lines. PHMSA proposed to 
define Type A, Area 2 regulated gathering lines as gathering lines 
located in Class 1 locations that meet the existing Type A features in 
the table in Sec.  192.9(b) (i.e., metallic with an MAOP that produces 
a hoop stress of 20 percent or more of SMYS, or non-metallic with an 
MAOP greater than 125 psig) that have a nominal pipe size of 8 inches 
or greater.
    This change was intended to improve the safety of larger-diameter, 
higher-stress gathering lines that were previously exempt from Federal 
safety regulations at part 192. In the NPRM, these newly designated 
Type A, Area 2 (Type C) regulated gathering lines would have to comply 
with a basic set of requirements as set forth in Sec.  192.9. The 
specific requirements for newly regulated gas gathering lines are 
discussed in section III.D of this document.
2. Summary of Public Comment
    API, the Michigan Public Service Commission (Michigan PSC), the 
Texas Pipeline Association (TPA), and Atmos Energy Corporation (Atmos) 
recommended that more data should be collected before determining the 
appropriate scope of additional regulations. The PAPUC supported the 
extension of regulatory oversight to gathering lines in Class 1 
locations, based on its experience with growing natural gas production 
in Pennsylvania, noting that gathering lines are being constructed with 
diameters equal to or larger than typical transmission lines and are 
being operated at much higher pressures than was typical in the past. 
NAPSR supported the proposed scope of the new gathering line 
requirements but also commented that its members believe all gathering 
lines should be required to comply with part 192, regardless of class 
location. Some environmental and safety groups also expressed support 
for the extension of regulations to gas gathering lines in Class 1 
locations in order to reduce the risks of incidents, greenhouse gas 
emissions and other air pollution. For example, EDF supported 
requirements for the design, installation, construction, initial 
inspection and testing, corrosion control, damage prevention and 
leakage surveys in order to reduce methane emissions.
    The North Dakota Petroleum Council, the Marcellus Shale Coalition, 
the AGA, the Plastics Pipe Institute (PPI), Spectra Energy Partners, 
API, GPA Midstream, the Northeast Gas Association, and some individuals 
submitted comments noting issues and uncertainty with the regulatory 
impact assessment. For example, GPA Midstream commented that the 
benefits analysis included information for offshore and Class 2 
incidents that are not applicable to the proposed scope of this final 
rule and that the cost analysis underestimated the time and cost to 
identify newly regulated gathering lines in a short amount of time and 
comply with the new requirements, especially MAOP determination and 
public awareness. Many operators and industry groups expressed 
disagreement with applying regulations to all Class 1 gas gathering 
lines with outer diameters of 8.625 inches or greater, arguing that 
gathering lines on the smaller end of that category do not represent 
the large-diameter, high-pressure gathering lines referenced in the 
preamble of the NPRM and public discussions. API commented that if 
PHMSA does proceed with defining a new category of regulated gathering 
lines, gathering lines with outer diameter greater than 16 inches have 
the potential to pose a higher risk and should be the criteria for 
determining regulated gathering, rather than 8 inches. API further 
suggested that targeting lines with outer diameters greater than 16 
inches would be more in the spirit of the risk-based philosophy of 
other parts of the code, such as integrity management. This suggestion 
was

[[Page 63280]]

repeated by GPA Midstream, the North Dakota, Petroleum Council, and 
others.
    A number of commenters representing the pipeline industry expressed 
concerns with the deadlines to identify newly regulated gathering lines 
and then comply with the proposed regulations. For example, Rice 
Energy, Dominion East Ohio, API, and GPA Midstream commented that the 
implementation timeframe for identifying proposed Type A, Area 2 (now 
Type C) regulated gathering lines was too short. Industry commenters 
were especially concerned about the deadline to establish an MAOP, 
especially if the MAOP verification requirements proposed for gas 
transmission lines in the NPRM also applied to gathering lines. One 
commenter suggested an economic criterion to allow an exemption for 
operators of economically marginal, low stress gathering lines.
    Some commenters expressed the view that the proposed Type A, Area 2 
(now Type C) classification for newly regulated gas gathering lines 
could be confusing. Specifically, commenters found that designating 
newly regulated gas gathering lines as Type A, Area 2 (now Type C), and 
then requiring those pipelines to follow requirements similar to Type B 
rather than existing Type A requirements was cumbersome and risked 
conflating distinct regulatory requirements. A few commenters suggested 
a Type C designation rather than the proposed Type A, Area 2 (now Type 
C) designation. The GPAC recommended PHMSA address these concerns in 
the final rule.
3. GPAC Recommendation
    GPAC voted 11-1 that the scope of newly regulated gas gathering 
lines in proposed Sec.  192.8(b) and (c) is technically feasible, 
reasonable, cost-effective, and practicable if PHMSA considered the 
following:
     Establishing an initial framework for regulating Class 1 
gathering lines that could be built upon in light of future information 
and experience;
     Setting a minimum set of requirements for gathering lines 
8.625 inches in outside diameter and greater (considering, for example: 
Damage prevention; line markers; public awareness; leak surveys and 
repairs; design, installation, construction, and initial inspection and 
testing for new lines; and emergency plans). Give due consideration to 
the GPAC discussion on the costs and benefits of performing leakage 
surveys;
     Consider applying a PIR concept and additional 
requirements to provide safety and environmental protection for larger- 
diameter gathering lines (e.g., greater than 12.75 inch outside 
diameter); and
     Ensuring that composite pipe \71\ was adequately addressed 
to minimize the impact on its continued use. Note that this is 
discussed in section III.D below.
---------------------------------------------------------------------------

    \71\ A composite pipe is made of a combination of either steel 
or plastic with a reinforcing material designed to maintain its 
circumferential and longitudinal strength. A common configuration 
consists of steel or fiber reinforcement layered between a polymer 
inside liner and outer shell. No composite materials are currently 
authorized for use in part 192 or part 195, but may be used through 
a special permit (see Sec.  190.341).
---------------------------------------------------------------------------

4. PHMSA Response
    In response to public comments and the recommendations of the GPAC, 
PHMSA has changed the proposed ``Type A, Area 2'' designation for newly 
regulated gas gathering lines to ``Type C'' lines. PHMSA originally 
proposed use of the term ``Type A, Area 2'' (now Type C) because the 
newly regulated gas gathering lines have features similar to existing 
Type A pipelines in the table in Sec.  192.8, except that they are 
located in Class 1 locations. However, PHMSA agrees that creating the 
category ``Type C'' may be less confusing. While adopting the new 
designation of Type C regulated gas gathering lines introduces some 
repetition in the table in Sec.  192.8, PHMSA believes it will make 
clearer that the three categories represent different levels of risk 
that warrant corresponding levels of regulation and will reduce 
unnecessary confusion among operators and inspectors in the future.
    The final rule continues to define Type C regulated gas gathering 
lines as gas gathering lines in Class 1 locations that are 8.625 inches 
or greater in diameter and are: (1) Metallic, with an MAOP producing a 
hoop stress of 20 percent or more of SMYS; (2) metallic, with an MAOP 
greater than 125 psig if the hoop stress is unknown; or (3) non-
metallic, with an MAOP greater than 125 psig. However, PHMSA recognizes 
that not all gathering lines that meet these criteria pose the same 
level of risk. Therefore, the final rule provides that the requirements 
that Type C gathering lines must comply with will vary, based on the 
scale of risk associated with the particular characteristics of the 
pipeline. The applicability of each of the requirements that 
potentially applies to Type C lines is described in section III.D below 
and the section-by-section analysis. Gathering lines smaller than 8.625 
inches in outside diameter or operating below the pressure or stress 
level criteria described above will remain unregulated under part 192 
and are subject only to incident and annual reporting in part 191 (see 
section III.A below).
    As described in the background section (II.A) above, modern 
gathering systems require larger, higher-pressure lines to meet the new 
supply and demand pressures than had been common when the existing 
requirements were put into place. This is not a theoretical problem: 
Failures on unregulated gas gathering lines have resulted in serious 
incidents, some with fatal consequences (see the discussion in section 
II.A above).
    PHMSA appreciates the need to exercise caution in exercising its 
statutory authority to regulate gathering lines that have not been 
previously covered by parts 191 and 192 without clear, detailed safety 
data. This is why a new category of gathering lines is being created 
for reporting purposes only that are only subject to the incident and 
annual reporting requirements described in section III.A of this 
document. These are designated as ``Type R'' gathering lines in Sec.  
192.8. These lines are not regulated gathering lines under in part 192 
but are subject to incident and annual reporting requirements in part 
191.
    However, there is ample basis upon which to add the targeted 
requirements in this final rule for Type C gathering lines that mirror 
the requirements already in place for existing, lower-stress Type B 
lines. These measures are an appropriate initial step to ensure basic 
safeguards to the public, property, and the environment while 
additional data is collected and analyzed. Additionally, withdrawing 
the proposed regulations in the NPRM for previously unregulated gas 
gathering lines in its entirety would be inconsistent with public 
safety and would not be responsive to GAO recommendation GAO-14-667 or 
the Congressional mandate in the 2020 PIPES Act. Therefore, PHMSA is 
adding the definition of Type C regulated gas gathering lines as 
proposed in the NPRM.
    However, the new regulatory requirements are tailored to the 
potential hazards the newly regulated gathering lines may pose. This is 
described in more detail in section III.D below. PHMSA determined that 
certain programs, such as damage prevention, are foundational to 
pipeline safety and public trust and therefore should be required for 
all Type C gas gathering lines as originally proposed in the NPRM. 
However, other requirements apply only to Type C lines with an outside 
diameter greater than 16 inches, and Type C lines with an outside

[[Page 63281]]

diameter larger than 12.75 inches that are located near homes and other 
structures. The largest-diameter gas gathering lines and those that can 
directly impact local communities are required to comply with all of 
the requirements for newly regulated Type C (Type A, Area 2) gathering 
lines proposed in the NPRM. The proposed deadline to determine 
endpoints of newly regulated gathering lines remains unchanged in the 
final rule--6 months after the effective date. Operators must therefore 
identify the endpoints of newly regulated Type C lines on or before 
November 16, 2022. While the GPAC recommended a 2-year compliance 
deadline for identifying the endpoints of Type C gathering lines, such 
a delay is not necessary given that PHMSA understands that many Type C 
lines are of more recent vintage and therefore would generally have 
more robust records to facilitate determination of endpoints than older 
gathering lines. A prolonged identification period would also delay the 
important safety (section III.D. infra) and reporting (section III.A.4. 
supra) standards in the final rule. The Type C determination in Sec.  
192.8(c)(2) requires, at a minimum, knowledge only of the location, 
diameter, and pressure of the pipeline. Most Type C gathering lines are 
relatively modern shale gas systems and these basic records should be 
readily accessible.
    PHMSA acknowledges that this deadline may be challenging for some 
operators of certain older, smaller-diameter, systems. The final rule 
therefore includes procedures for an operator to request an alternative 
compliance deadline with a notification in accordance with Sec.  
192.18. This is intended to mirror existing Sec.  192.9(e)(2), which 
gives the PHMSA Administrator discretion to allow a later deadline if 
justified in a particular case. An operator must submit a written 
request to PHMSA in accordance with Sec.  192.18 no later than 90 days 
prior to the standard compliance deadline. The request must include, at 
a minimum, a description of the facilities that require a delayed 
compliance date, the justification for an alternative compliance 
deadline, and the proposed alternative compliance deadline. An operator 
may proceed with their proposed compliance deadline if they receive a 
no-objection letter from PHMSA or if PHMSA does not reply within 90 
days. If delayed identification impacts an operator's ability to comply 
with the requirements in Sec.  192.9, they must submit a separate 
notification to request delayed compliance under that section.
    The combination of changes discussed in this section and in section 
III.D below provides a reasonable and cost-effective initial approach 
to address the risks associated with previously unregulated gas 
gathering lines. PHMSA will monitor the safety performance of both 
newly regulated gas gathering and unregulated gas gathering lines and 
evaluate the need for further regulatory action in the future.

D. Safety Requirements for Newly Regulated Gas Gathering Lines--
Sec. Sec.  192.9, 192.13, 192.18, 192.452, and 192.619

1. Summary of PHMSA's Proposal
    PHMSA proposed in the NPRM to apply part 192 safety requirements to 
the newly-established Type A, Area 2 lines (referred to as Type C lines 
in the final rule). These requirements, collectively referred to as 
Type C requirements in this final rule, are:
     Sec.  192.9(d)(1)--Implement design, installation, 
construction, initial inspection, and initial testing requirements for 
new/replaced/relocated/changed lines in accordance with the 
requirements in part 192 for transmission lines.
     Sec.  192.9(d)(2)--Adopt corrosion control measures for 
metallic pipe in accordance with part 192, subpart I, requirements for 
transmission lines.
     Sec.  192.9(d)(3)--Adopt damage prevention measures in 
accordance with Sec.  192.614.
     Sec.  192.9(d)(4)--Develop public awareness programs in 
accordance with Sec.  192.616.
     Sec.  192.9(d)(5)--Establish MAOP in accordance with Sec.  
192.619.
     Sec.  192.9(d)(6)--Install and maintain line markers in 
accordance with the requirements for transmission lines in Sec.  
192.707.
     Sec.  192.9(d)(7)--Conduct leakage surveys in accordance 
with Sec.  192.706, using leak- detection equipment and promptly repair 
hazardous leaks that are discovered, in accordance with Sec.  
192.703(c).
     Sec.  192.9(d)(8)--Develop and implement procedures for 
emergency plans in accordance with Sec.  192.615.
    These requirements are the same as those that currently apply to 
Type B regulated gas gathering lines, except for the new emergency 
plans requirements. PHMSA also proposed conforming changes to 
Sec. Sec.  192.13, 192.452, and 192.619.
2. Summary of Public Comment
    Citizen and environmental groups expressed support for the proposed 
requirements for newly regulated gas gathering lines or suggested 
additional requirements. Several citizen groups suggested that gas 
gathering lines that function similarly to transmission lines should be 
regulated like transmission lines in part 192. Similarly, the Public 
Service Commission of West Virginia commented that the proposed 
requirements for Type A, Area 2 (now Type C) lines, which mirror the 
requirements for low-pressure, low-stress Type B gathering lines, are 
not adequate or sufficient to ensure the safety of large, high-pressure 
gas gathering lines and instead recommended that such pipelines follow 
existing Type A, Area 1 requirements (i.e. most gas transmission line 
requirements) that apply to other regulated gathering lines that 
operate with higher stress levels and pressures.
    GPA Midstream and Kinder Morgan commented that Type A, Area 2 (now 
Type C) lines should not have to conduct leakage surveys with leak 
detection equipment, as currently required for Type B gathering lines 
in Sec.  192.9(d)(7), since leaks and ruptures on higher-stress Type A 
lines are easier to detect without specialized equipment. API and TPA 
proposed that the emergency-planning requirements in Sec.  192.9(d)(8) 
be revised to reference the existing requirements for other types of 
pipelines in Sec.  192.615. They also recommended exempting operators 
of Type A, Area 2 (now Type C) regulated gathering lines from the 
requirement to have written procedures to respond to each of the 
emergency situations listed in Sec.  192.615(a)(3), presumably for cost 
concerns. API, GPA Midstream, and Northeast Gas Association commented 
that the compliance cost estimates used in the RIA for Type A, Area 2 
(now Type C) regulated gathering lines were underestimated and 
contained erroneous assumptions. For example, GPA Midstream raised 
concerns about the costs of program evaluation requirements under 
public awareness. Industry commenters were especially concerned about 
the applicability of the proposed gas transmission requirements in the 
NPRM such as the MAOP reconfirmation, including the cost to establish 
MAOP and confirm the material properties of gathering lines that were 
not previously required to have an MAOP or keep such records. PHMSA 
notes that these provisions were finalized by the Gas Transmission 
Final Rule and apply only to gas transmission lines.
    A number of commenters articulated concerns about how the proposed 
regulations would affect the use of non-metallic materials in 
previously

[[Page 63282]]

unregulated gathering systems. Commenters representing gathering line 
operators and non-metallic pipe manufacturers urged PHMSA to consider 
the impact of the rule on gathering lines made of composite materials 
and polyethylene pipe manufactured to standards other than ASTM D2513. 
A composite pipe is made of a combination of either steel or plastic 
with a reinforcing material designed to maintain its circumferential 
and longitudinal strength. A common configuration consists of steel or 
fiber reinforcement layered between a polymer inside liner and outer 
shell. No composite materials are currently authorized for use in part 
192 or part 195 but may be used through a special permit (see Sec.  
190.341).
    Commenters were especially concerned with the possibility that 
existing, unregulated lines made of non-metallic materials would need 
to be replaced if they subsequently become regulated Type A, Area 2 
(Type C) lines. API suggested that PHMSA incorporate by reference two 
standards, API Standard 15S, ``Spoolable Composite Pipe Systems,'' 1st 
edition and ASTM F2619/F2619M-13, ``Standard Specification for High-
Density Polyethylene (PE) Line Pipe'' into Sec.  192.9 to allow the use 
of composite materials and an alternative specification for 
polyethylene pipe that is commonly used in unregulated production and 
gathering operations. API and the Plastic Pipe Institute commented that 
the proposed repair criteria in the NPRM did not address non-metallic 
materials and could effectively eliminate the use of plastics and 
composites in Type A, Area 2 (now Type C) lines that previously had no 
such restrictions. GPA Midstream also commented that composite pipe can 
operate at pressures that would include them within the Type A, Area 2 
(now Type C) criteria and should therefore be addressed in the rule.
3. GPAC Recommendations
    GPAC voted 12-0 that the proposed minimum safety standards for Type 
A, Area 2 (Type C) regulated gathering lines were technically feasible, 
reasonable, cost-effective, and practicable, if the following changes 
were made:
     Extend the deadline for Type A, Area 2 (Type C) gathering 
lines that become regulated in the future due to new dwellings to 
comply with part 192 requirements from one year to two years after the 
effective date of the final rule;
     Add a notification process similar to the process endorsed 
by the committee for the gas transmission rule \72\ to address the use 
of composite pipe materials in existing and new Type A, Area 2 (Type C) 
gathering lines;
---------------------------------------------------------------------------

    \72\ This recommendation was subsequently codified as Sec.  
192.18 by the Gas Transmission Final Rule (84 FR 52180).
---------------------------------------------------------------------------

     Extend the deadline in Sec.  192.8(b) for determining if 
pipelines are classified as Type A, Area 2 (Type C) gathering lines 
from six months to two years after the effective date of the final 
rule;
     Extend the deadline for newly regulated gas gathering 
lines to comply with Type A, Area 2 (Type C) requirements to three 
years after the effective date of the rule, and make conforming changes 
(Sec. Sec.  192.9(e)(3) and (4), 192.452, 192.13, and 192.619);
     Ensure that the language for designating newly regulated 
gas gathering lines is as clear as possible (e.g., Type C vs. Type A, 
Area 2);
     Allow operators of Type A, Area 2 (Type C) gas gathering 
lines to establish MAOP based on a five-year high operating pressure; 
or via an alternative method with notification to PHMSA (Sec.  192.18 
process); and
     Modify Sec.  192.9 (d) to include Type A, Area 2 (Type C) 
gathering lines.
4. PHMSA Response
    PHMSA understands the concerns expressed by the commenters 
regarding the application of existing pipeline safety requirements to 
newly regulated gas gathering lines. While the final rule does not 
significantly change the NPRM's proposed criteria for designating newly 
regulated Type C gas gathering lines (higher stress gathering lines 
with an outside diameter of 8.625 inches or greater, see section 
III.C), it does make changes to the NPRM's proposal regarding how each 
of the proposed Type C requirements are to be applied. These changes 
focus on applying more requirements to the highest-risk, largest-
diameter gathering lines. The risk-based approach to Type C 
requirements in this final rule is based upon discussions at the June 
25th GPAC meeting, consideration of the public comments received on the 
NPRM, and an analysis of the costs and benefits of various alternatives 
(see the RIA, available in the docket for this rule, for a detailed 
description of alternatives considered). As discussed during the GPAC 
meeting, PHMSA emphasizes that the Type C requirements are an initial 
step in addressing safety concerns with larger-diameter gas gathering 
lines. If PHMSA's analysis of the safety performance of regulated and 
unregulated gathering lines demonstrates a need to revise the 
requirements for regulated gathering lines, PHMSA can exercise its 
authority to do so in a future rulemaking.
    The applicability of each of the requirements for Type C regulated 
gas gathering lines in the final rule is as follows:
    Requirements for Type C gathering lines with outside diameters of 
8.625 inches and greater:
     Design, installation, construction, and initial inspection 
and testing for lines that are new, replaced, relocated, or otherwise 
changed after the applicable compliance date in Sec.  192.13 per 
transmission line requirements in part 192;
     Corrosion Control (part 192, subpart I);
     Damage Prevention Program (Sec.  192.614);
     Emergency Plans (Sec.  192.615);
     Public Awareness (Sec.  192.616);
     Line Markers (Sec.  192.707); and
     Leakage Surveys (Sec.  192.706).
    Additional requirements for Type C gathering lines with outside 
diameters greater than 12.75 inches:
     Applicable requirements of part 192 for plastic pipe and 
components; and
     Establishment of MAOP (Sec.  192.619).
    Exception: Gathering lines with an outer diameter 16 inches or less 
that are not located within a potential impact circle containing a 
building intended for human occupancy or other impacted sites must only 
comply with requirements governing damage prevention (Sec.  192.614); 
emergency plans (Sec.  192.615); and, for Type C lines that are new, 
replaced, relocated, or otherwise changed after the applicable 
compliance date in Sec.  192.13 (i.e. 1 year after the effective date 
of the rule), certain design, installation, construction, initial 
inspection, and initial testing requirements applicable to transmission 
lines under part 192. These provisions are required for all Type C 
gathering lines regardless of size or location. The applicability of 
each of these requirements is summarized in the table below:

[[Page 63283]]

------------------------------------------------------------------------
                               Not located near a      Located near a
                                building intended     building intended
                               for human occupancy   for human occupancy
      Outside diameter          or other impacted     or other impacted
                                   site (Sec.            site (Sec.
                                    192.9(f))             192.9(f))
------------------------------------------------------------------------
Greater than or equal to      --Design,             --Design,
 8.625 inches up to and        Construction,         Construction,
 including 12.75 inches.       Initial Inspection    Initial Inspection
                               and Testing (new/     and Testing (new/
                               replaced/relocated/   replaced/relocated/
                               changed lines).      changed lines).
                              --Damage Prevention.  --Corrosion Control.
                              --Emergency plans     --Damage Prevention.
                                                    --Emergency Plans.
                                                    --Line Markers.
                                                    --Public Awareness.
                                                    --Leakage Surveys.
Greater than 12.75 inches up  --Design,             All Type C
 to and including 16 inches.   Construction,         Requirements.
                               Initial Inspection
                               and Testing (new/
                               replaced/relocated/
                               changed lines).
                              --Damage Prevention.  ....................
                              --Emergency Plans.    ....................
Greater than 16 inches......  All Type C            All Type C
                               Requirements          Requirements.
------------------------------------------------------------------------

    The potential impact circle calculation criterion for certain Type 
C requirements is based on the method for identifying high-consequence 
areas in the gas transmission integrity management program regulations 
in subpart O of part 192. Specifically, the terms ``potential impact 
circle'' and ``potential impact radius (PIR),'' including the formula 
for calculating what the length of the potential impact radius,\73\ are 
defined in Sec.  192.903. The ``potential impact circle'' is the area 
around a pipeline where a pipeline rupture could cause severe 
consequences, such as casualties and destruction of property. PHMSA 
notes that the formula requires knowing the MAOP of the pipeline, 
rather than the actual operating pressure. Additionally, the final rule 
requires that operators of Type C gathering line use a factor of 0.73 
for wet/rich natural gas in the PIR calculation rather than the 0.69 
factor for dry natural gas used in the integrity management 
regulations. This results in a slightly larger potential impact circle 
reflecting the potentially more intense fire and explosion hazards due 
to the higher average energy content of unprocessed gas, which may 
contain higher concentrations of natural gas liquids and other 
hydrocarbons. A 2005 report prepared for PHMSA by Michael Baker Jr., 
Inc., titled, ``Potential Impact Radius Formulae for Flammable Gases 
other than Natural Gas Subject to 49 CFR 192'' \74\ calculated that 
0.73 was an appropriate PIR factor for pipelines transporting rich 
natural gas. The calculations are detailed in section 4.8.4 of the 
report using the same formula described in ASME B31.8S that is 
referenced in the gas transmission integrity management regulations. 
API RP 1182 uses the same factor for a similar PIR concept, however 
that document is not incorporated by reference in this rule. Similarly, 
Sec.  192.9(f) in this final rule dictates that any Type C gathering 
line segment located within a potential impact circle containing a 
building intended for human occupancy or other impacted site must 
comply with all Type C requirements applicable for the diameter of that 
line, since a failure on that segment has the potential to cause 
catastrophic damage to local communities. This approach was discussed 
at the GPAC and in public comments and PHMSA agrees it is an effective 
way of prioritizing short-term regulatory action towards gas gathering 
lines with the highest potential consequences of a failure.
---------------------------------------------------------------------------

    \73\ See ASME B31.8S for additional information on calculating 
PIR.
    \74\ Michael Baker Jr., Inc. ``TTO Number 13: Potential Impact 
Radius Formulae for Flammable Gases Other than Natural Gas Subject 
to 49 CFR 192: Final Report'' (June 2005), https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/gas-transmission-integrity-management/65311/tto13potentialimpactradiusfinalreportjune2005.pdf.
---------------------------------------------------------------------------

    PHMSA recognizes that not all operators may be able to perform the 
potential impact radius calculation. If the gathering line segment does 
not have an established MAOP or other records necessary to perform the 
PIR calculation, the operator may perform the same determination on a 
class location unit (see Sec.  192.5) basis rather than a potential 
impact circle basis. A class location unit is 1 mile in length and 
extends 220 yards on either side of the centerline of a pipeline. PHMSA 
notes that this uses the same ``sliding mile'' approach used for 
determining class locations rather than static mile-long increments 
stacked end-over-end. The class-location unit moves along the pipeline, 
and if the sliding mile contains a building intended for human 
occupancy or other impacted site at any point during the mile's 
movement, then the exception in paragraph (f) does not apply for the 
entire mile of pipeline contained within the sliding mile.
    The class location unit method for applying these exceptions is 
used in API RP 1182 and provides a simpler, more conservative method 
for determining the applicability of the Sec.  192.9(f) exception for 
operators that choose not to perform a PIR analysis or lack records of 
the parameters necessary to calculate the PIR. PHMSA expects that the 
class location unit method will result in fewer miles of gathering 
lines being covered by the Sec.  192.9 exception in almost all 
circumstances because the additional requirements will apply for a mile 
on each side of a building intended for human occupancy or other 
impacted site. Theoretically, the PIR of a pipeline could exceed 220 
yards; if this is the case it is possible that some structures could be 
captured by the PIR analysis but not the class location unit analysis. 
However, given that this exception is limited for Type C gathering 
lines 16 inches or less in outside diameter, it is unlikely that a 
gathering line 16 inches or less in diameter will operate at a pressure 
that would cause the calculated PIR to exceed the width of the class 
location unit. The MAOP of a pipeline with an outside diameter of 16 
inches must exceed 3000 psig for the PIR of the pipeline to exceed 660 
feet. A MAOP of 3000 psig is unusually high. Although PHMSA does not 
collect data on MAOP on annual reports, incident reports reveal that 
less than 1 percent of gas transmission incidents from 2010 through the 
end of 2021 involved a facility with an MAOP higher than 3000 psig; 
further, there were no incidents volving a pipeline larger than 10.75 
inches in outside diameter, and no incidents on regulated onshore gas 
gathering lines.
    In the final rule, operators must achieve compliance with 
applicable Type C requirements no later than 1

[[Page 63284]]

year after the effective date of the rule, unless PHMSA has approved an 
alternative compliance schedule after the operator has submitted a 
notification in accordance with Sec.  192.18. This is a shorter 
compliance deadline than the 3-year phase in recommended by the GPAC 
(i.e., 1-year after the endpoints of Type C have been identified). The 
safety standards in the final rule target known threats to public 
safety, and the most significant requirements are targeted at gathering 
lines with direct potential safety impacts (i.e., has a potential 
impact circle containing a building intended for human occupancy). Due 
to these direct threats to the public, it is critical that operators 
implement minimum safety practices as soon as practicable. The final 
rule provides operators a total of 1\1/2\ years from the date of 
publication to implement these measures, which should be achievable for 
most operators.
    However, PHMSA recognizes that some operators may encounter 
challenges in meeting the deadline for one or more of the Type C 
requirements. The final rule therefore includes procedures for an 
operator to request an alternative compliance deadline with a 
notification in accordance with Sec.  192.18. This is intended to 
mirror existing Sec.  192.9(e)(2), which allows the PHMSA Administrator 
flexibility to provide a later deadline if justified in a particular 
case. An operator must submit a written request to PHMSA in accordance 
with Sec.  192.18 no later than 90 days prior to the standard 
compliance deadline. The request must include, at a minimum, a 
description of the facilities that require a delayed compliance date, 
the proposed alternative deadline, justification for the alternative 
compliance deadline, and actions the operator will take to ensure the 
safety of the affected facilities in the interim. The description of 
the pipeline facility and the operating environment should include 
relevant information about the integrity of the pipeline and the 
potential consequences in the case of the release. This includes: The 
diameter of the pipeline; the operating pressure; known design and 
construction specifications; results from surveys, patrols, or 
integrity assessments; and the presence of homes or other human uses 
near the pipeline. An operator may request an alternative compliance 
schedule for more than one requirement within Sec.  192.9(e) in a 
single notice. However, the notice must include a proposed compliance 
schedule and justification for each requirement. An operator may 
proceed with their proposed compliance deadline if they receive a no-
objection letter from PHMSA or if PHMSA does not reply within 90 days.
    Consistent with the deadlines described above, design, 
construction, initial inspection, and initial testing requirements 
apply to all Type C lines that are new, replaced, relocated, or 
otherwise changed after the applicable compliance deadline in Sec.  
192.13 (i.e., 1 year after the effective date of the rule). 
Additionally, in the final rule, operators of unregulated gas gathering 
lines that become Type C regulated gathering lines, or become subject 
to additional Type C requirements, due to a change in the pipeline's 
MAOP or the discovery of a building intended for human occupancy or 
other impacted site have 1 year from the time the change is discovered 
to comply with Type C requirements.
    PHMSA determined that it was appropriate for all Type C gathering 
lines that are new, replaced, relocated, or otherwise changed after the 
applicable compliance date in Sec.  192.13 (i.e., 1 year after the 
effective date of the rule) to comply with the initial design, 
construction, inspection, and testing requirements applicable to 
transmission lines in part 192 to ensure that new, higher risk 
gathering lines are adequately designed and constructed. PHMSA also 
determined that it was appropriate for all Type C gathering lines to 
comply with damage prevention and emergency plan requirements in 
Sec. Sec.  192.614 and 192.615, based on the incident history of 
transmission pipelines and fatal gas gathering incidents. For onshore 
gas transmission lines between 2010 and 2019, excavation damage was the 
third leading cause of incidents and the most common cause of incidents 
that resulted in fatal injuries.\75\ As described in section II.A, many 
of the fatal incidents on unregulated gathering lines described in 
media reports have been caused by excavation damage. These incidents 
commonly cause serious and fatal injuries regardless of the diameter or 
location of the pipeline since equipment operators and other workers 
may be in close proximity to the point of failure. However, effective 
damage prevention programs and participation in One-Call programs can 
reduce this risk. Based on gas transmission line incident report data, 
both the number of excavation damage incidents and the share of 
incidents caused by excavation damage has trended downwards between 
2000 and 2018. While gathering lines are covered under damage 
prevention and One-Call laws in most States, PHMSA expects that 
requiring operators to implement a damage prevention program under part 
192 may improve enforcement of these requirements and cover lines in 
States where gathering lines are excepted. Maintaining a written damage 
prevention procedure and communicating damage prevention information to 
the public may also result in safety benefits beyond compliance with 
State One-Call laws from operators and excavators becoming more 
cognizant of the risks of third-party damage to gathering lines.
---------------------------------------------------------------------------

    \75\ Out of 1,057 incidents reported to PHMSA that occurred 
during this period, 150 were due to excavation damage. Of the 13 
incidents that resulted in fatal injuries, 6 were caused by 
excavation damage.
---------------------------------------------------------------------------

    The requirements for emergency plans in Sec.  192.615 directly 
address concerns with operator and community emergency response and 
planning capability. Emergency response plans and procedures for rural 
gathering lines were areas of emphasis in GAO's August 2014 report on 
safety requirements for transporting energy products.\76\ In that 
report, the NTSB, a representative of the National Association of State 
Fire Marshals and emergency response officials agreed that ``emergency 
response plans are critical for pipeline safety;'' however, those 
emergency officials were concerned that responders in rural areas 
lacked the information about unregulated gathering lines in their 
communities to prepare for and respond to pipeline emergencies. 
Requiring all Type C gathering lines to comply with Sec.  192.615 
addresses these concerns by bringing emergency planning requirements 
for such pipelines in line with existing requirements for gas 
transmission lines.
---------------------------------------------------------------------------

    \76\ GAO, GAO-14-667, ``Oil and Gas Transportation: Department 
of Transportation is Taking Actions to Address Rail Safety, but 
Additional Actions are Needed to Improve Pipeline Safety'' (Aug. 
2012).
---------------------------------------------------------------------------

    PHMSA disagrees with the comment that Type C gas gathering lines 
should be excepted from the requirement to develop and follow 
procedures for responding to common types of pipeline emergencies 
listed in Sec.  192.615(a)(3), such as gas leaks in structures, fires, 
explosions, and natural disasters. This requirement is necessary to 
help ensure effective emergency preparedness. As described in the 
background section II of this document and the GAO-14-667 report, 
emergency response capabilities are especially important for gas 
gathering systems operating in communities that do not have experience 
with intensive oil and gas development.
    Design, installation, construction, initial inspection, and initial 
testing

[[Page 63285]]

requirements, and corrosion control measures in part 192 are intended 
to reduce the likelihood of a release caused by material and equipment 
failure, corrosion, and excavation damage. Design, installation, 
construction, initial inspection, and initial testing requirements are 
prospective only. Operators are not expected to replace facilities 
existing on or prior to the compliance deadline in Sec.  192.13 (i.e., 
1 year after the effective date of the rule) in order to comply with 
these requirements. PHMSA expects there will be safety benefits from 
applying part 192 design, construction, initial inspection, and initial 
testing requirements should those existing lines require replacement, 
relocation or otherwise be changed.
    In the NPRM, PHMSA did not intend to prohibit the use of composite 
pipe materials on previously unregulated Type C gathering lines or 
require the removal of such materials. However, the existing part 192 
requirements were written for steel or conventional plastic pipe. 
Additionally, the NPRM did not propose to incorporate by reference API 
RP 15S or F2619/F2619M-13 and PHMSA has not yet conducted the technical 
review of those documents needed to support their incorporation by 
reference in this final rule.
    To address composite pipe, PHMSA has added a provision in the final 
rule to allow operators to install or replace composite pipe that is 
not otherwise authorized by part 192 for use in regulated Type C gas 
gathering lines upon notification to PHMSA pursuant to Sec. Sec.  
192.9(h) and 192.18. Operators may use composite pipe or materials as 
proposed in their notification if, after 91 days, they have not 
received a letter from PHMSA with either an objection to the proposed 
use of composite pipe, or that states that PHMSA requires additional 
time to conduct its review. PHMSA may also proactively issue a no-
objection letter. Additionally, operators may continue to use composite 
pipe installed on or before the effective date of the rule; no 
notification under Sec. Sec.  192.9(h) and 192.18 would be required in 
those circumstances. This change affects Type C gathering lines only 
and does not authorize the use of composite pipe for any other type of 
pipeline covered under part 192. Under the Sec.  192.18 notification 
process, PHMSA will evaluate the operator's proposed operation and 
maintenance procedures, which includes the operator's proposed 
remediation methods and procedures for identifying defects and 
determining the safe operating pressures of composite pipe when defects 
are found. PHMSA will not approve notifications that it determines are 
inconsistent with pipeline safety. An objection letter issued under 
Sec.  192.18 will not foreclose an operator's ability to seek a special 
permit in accordance with Sec.  190.341. Additional information on this 
process is provided in the section-by-section analysis of this 
document. PHMSA may use data obtained from observing the design, 
construction, and operation of composite materials in Type C gathering 
lines to inform its future decisions on whether and how to accept 
composite materials for pipelines in other jurisdictional applications.
    Public awareness requirements in Sec.  192.616 and line marker 
requirements in Sec.  192.707 apply to Type C lines that are located 
near buildings intended for human occupancy, and further address 
residual risks despite part 192 damage prevention and emergency 
planning requirements. Public awareness requirements in Sec.  192.616 
require additional communication with excavators, first responders, 
local governments, and the public. Notably, this provision at Sec.  
192.616(d) obliges operators to describe the potential hazards of a 
pipeline release, the physical markers of a release, and how to respond 
to customers and other members of the community. This requirement is 
especially important for members of the public to identify dangerous 
releases on gas pipelines that are not odorized. These communications 
improve safety by encouraging individuals to take safe actions such as 
contacting One-Call before performing excavations and recognizing, 
avoiding, and reporting gas leaks. Section 192.707 requires the 
placement of line markers at road and railroad crossings, and wherever 
else the operator deems is necessary. These markers provide a visual 
reminder of the presence of otherwise invisible pipelines and serve to 
reduce third-party damage risks. Additionally, during emergencies, line 
markers communicate hazards and operator contact information to first 
responders.
    After consideration of public comments, the recommendations of the 
GPAC, and the final RIA that accompanies this final rule, PHMSA has 
retained the requirement for leakage surveys in Sec.  192.706 for both 
(1) all Type C gathering lines with an outside diameter greater than 16 
inches, as well as (2) Type C gathering lines with an outer diameter 
greater than 8.625 inches but not exceeding 16 inches in outside 
diameter that are located in a potential impact circle containing a 
building intended for human occupancy or other impacted site. In other 
words, this requirement applies to larger-diameter gas gathering lines 
and those that could directly impact nearby structures and people 
during a rupture. Since Class 1 gas gathering lines are not typically 
odorized and the leakage survey requirement applies to larger diameter 
Type C gathering lines or those located near people, PHMSA has retained 
the requirement that operators use leak detection equipment when 
conducting leakage surveys. Leak detection equipment is already 
required for leakage surveys on gas transmission lines that are not 
odorized.
    Part 192 does not currently establish technology or performance 
standards for leak detection equipment, and the NPRM did not propose to 
establish standards for leak detection equipment. The final rule 
therefore does not specify what constitutes ``leak detection 
equipment.'' Any equipment capable of detecting all leaks on the 
pipeline system would be acceptable.\77\ Traditionally, operator 
personnel perform an instrumented leakage survey by walking along the 
pipeline right-of-of way with handheld leak detection equipment, such 
as a flame ionization detection device, laser-based methane detector, 
or other equipment. Similar equipment can be installed on vehicles or 
at fixed locations along the right of way. Some technology providers 
claim to detect smaller leaks from greater distances using a 
combination of vehicular or aerial sensor platforms, sensitive gas 
detectors, other sensors, and analytics. There are also various methods 
for continuous leak monitoring, including pressure and pressure wave 
monitoring, fixed gas detectors, and fiber optic-based distributed 
sensing. Performing leakage surveys increases the likelihood that small 
defects are discovered and remediated before they evolve into more 
significant failures with potentially severe impacts to people, nearby 
structures, and the environment. Leakage surveys are also necessary to 
mitigate the climate change impacts of methane leaks.
---------------------------------------------------------------------------

    \77\ See, e.g., PHMSA, Interpretation Letter No PI-01-0104, 
Letter to Richard Motsinger (Apr. 3, 2001), https://www.phmsa.dot.gov/regulations/title49/interp/PI-01-0104.
---------------------------------------------------------------------------

    Lastly, consistent with the GPAC recommendations, PHMSA adopts the 
remaining requirements proposed in the NPRM for application to all Type 
C lines with an outside diameter of greater than 16 inches, and Type C 
lines with an outside diameter greater than 12.75 inches but not 
exceeding 16 inches in outer diameter, that are located near buildings 
intended for human

[[Page 63286]]

occupancy or other impacted sites. For example, MAOP determinations 
will also be required for Type C gathering lines with an outside 
diameter greater than 16 inches, and Type C lines larger than 12.75 
inches in outside diameter up to and including 16 inches in outside 
diameter that are located in a potential impact circle containing a 
building intended for human occupancy or other impacted sites. The 
amendments proposed in the NPRM to the tables in Sec.  192.619(a)(3) 
that would give existing Type C gathering lines the option of 
establishing an MAOP based on historical operating pressure have been 
incorporated into the final rule. Therefore, newly regulated Type C 
lines now will have the option of establishing MAOP using the highest 
actual operating pressure to which the segment was subjected during the 
five years (60 months) preceding the effective date of the rule, or 
five years (60 months) before first becoming subject to the rule, 
whichever is later.
    However, PHMSA supports the GPAC recommendation to allow operators 
of Type C gas gathering lines to establish MAOP using alternative 
methods pursuant to the notification process set forth in Sec.  192.18 
and the requirements of Sec.  192.619(c)(2). PHMSA is persuaded that 
allowing alternative methods with PHMSA approval under Sec.  192.18 for 
establishing the MAOP of a previously unregulated Type C gas gathering 
line existing on or before the effective date of the rule is 
appropriate. Such operators were not previously required to make and 
maintain records of MAOP, pressure tests, or operating pressure and may 
not have traceable, verifiable, and complete records necessary to 
calculate an MAOP using the lowest of each of the methods listed in 
Sec.  192.619. This final rule includes a new Sec.  192.619(c)(2) and 
conforming changes to Sec.  192.18 to allow an operator of an existing 
Type C regulated gathering lines based on available records. Under this 
process, the operator would propose an MAOP based on the information 
available about the pipeline, such as actual highest operating 
pressure, operational and maintenance history, pressure test records, 
and information about the design and material properties of the 
pipeline. The new paragraph specifies the minimum information required 
to be submitted to PHMSA in the notification. The ``no objection'' 
process in Sec.  192.18 requires PHMSA to respond within 90 days. If, 
after 90 days, PHMSA has not responded to the notification, the 
operator would be allowed to use the ``other technology'' method to 
establish MAOP. This approach is not permitted for natural gas pipeline 
facilities other than Type C regulated gathering lines.
    The risk-based application of each of these Type C requirements is 
based on the operational and functional characteristics of those lines 
and strikes an appropriate balance between the need to protect people 
and the environment from the risks associated with large-diameter, 
high-pressure gathering lines and the need to exercise caution imposing 
regulatory burdens before more detailed information can be collected. 
The most substantive requirements apply to all Type C gathering lines 
with outer diameter of more than 16 inches and Type C gathering lines 
larger than 12.75 inches up through and including 16 inches that could 
directly affect homes, businesses, and other building intended for 
human occupancy. This approach focuses more stringent compliance 
measures on gas gathering lines that pose the most significant 
potential hazard to people and the environment. The requirements that 
remain for Type C gathering lines with an outside diameter of 12.75 
inches or less include initial design, construction and testing 
requirements, leakage surveys emergency planning, damage prevention, 
and corrosion control. While the GPAC recommended PHMSA consider 
applying leakage survey requirements to all Type C gathering lines, 
PHMSA has concluded that more detailed information on the extent and 
safety performance of such pipelines is needed to justify applying 
those requirements for Type C lines 16 inches in outside diameter and 
smaller that do not have a building intended for human occupancy within 
the PIR. However, as discussed at the GPAC meeting and in this final 
rule, PHMSA will use the data collected from the new reporting 
requirements to evaluate continuously PHMSA's oversight of gas 
gathering lines and determine if additional requirements are 
appropriate in the future.
    There is no potential impact circle or class-location unit-based 
exception for Type C gathering lines larger than 16 inches in outside 
diameter. PHMSA considered alternatives raised in the GPAC discussions 
and public comments, such as having no limit to the potential impact 
circle exception or limiting it to an outside diameter of 24 inches. 
After considering these factors and the revised RIA, PHMSA ultimately 
determined that the 16-inch limit for the PIR exception initially 
presented to the committee was appropriate. PHMSA notes that API and 
other industry commenters on the NPRM suggested 16 inches or greater, 
without a PIR exception, as an alternative definition for Type C. Many 
of the Type C requirements applicable to larger pipelines relate to 
initial design, construction, and corrosion control issues, and it is 
important for such pipelines to be properly constructed, tested, 
coated, and have cathodic protection applied before new homes and other 
buildings intended for human occupancy are built nearby in the future--
because such measures reduce associated safety risks. Additionally, the 
volume of a pipeline and the energy released during a rupture increase 
exponentially as pipe diameter increases. A rupture on a larger-
diameter pipeline, all else being equal, is therefore more likely to 
have consequences other than direct damage to structures. These include 
externalized economic disruptions to downstream users and environmental 
consequences such as methane emissions and ecological damage. These 
external consequences can be significant even if the potential impact 
radius of a pipeline segment is smaller than the width of a gas 
transmission class location unit (660 ft.).
    The NPRM's other proposed changes, including revisions to Sec.  
192.619(a)(4) and 192.619(e), only apply to gas transmission lines. In 
the Gas Transmission Final Rule, PHMSA clarified which new regulatory 
requirements from the NPRM apply only to gas transmission lines by 
including exceptions to those requirements for Type A and Type B 
gathering lines Sec.  192.9(c). In this final rule, Type C lines are 
also exempt from these requirements. Several other regulatory changes 
proposed in the NPRM, specifically the proposed repair criteria, were 
intended to apply solely to gas transmission lines. PHMSA expects to 
clarify the applicability of those requirements when the final rule 
addressing the repair criteria for gas transmission lines is published 
under RIN 2137-AF39.
    In response to comments and additional analysis, PHMSA has also 
updated the RIA. The revisions and clarifications described above 
reduce the cost of the requirements in Sec.  192.9. Specifically, the 
most significant of the proposed requirements will now apply only to 
large-diameter pipelines and certain smaller-diameter pipelines that 
are located within a potential impact circle containing a building 
intended for human occupancy or other impacted sites. Additionally, 
clarifying that the recordkeeping, material verification, and MAOP 
reconfirmation requirements proposed in the NPRM were not intended to 
apply to gathering or distribution lines addresses a large share

[[Page 63287]]

of the cost concerns raised in the comments.

IV. Section-by-Section Analysis

Sec.  191.1 Scope

    Part 191 prescribes requirements for the reporting of incidents, 
safety-related conditions, annual pipeline summary data, National 
Operator Registry information, and other miscellaneous conditions by 
operators of gas pipelines. Section 191.1 identifies the scope of 
applicability of the reporting requirements. PHMSA is revising Sec.  
191.1(a) to more clearly state that part 191 applies to offshore and 
onshore gas gathering not excepted by Sec.  191.1(b). This change is 
intended to define the existing scope of part 191 to offshore gas 
gathering lines and the revised applicability to onshore gas gathering 
lines in plain language. PHMSA is revising Sec.  191.1(b) to remove the 
exception to part 191 in Sec.  191.1(b)(4) for unregulated, onshore gas 
gathering lines, including gathering lines that operate at less than 0 
psig or are located within the inlets of the Gulf of Mexico. Incident 
Reports and Annual Reports will now be required for all onshore gas 
gathering lines, including Type R gathering lines. The expanded 
reporting requirements for previously unregulated gas gathering lines 
will provide data for monitoring the safety performance of these 
pipelines and a sound basis for evaluating if future regulatory changes 
are needed. However, this final rule excepts Type R gas gathering lines 
from requirements for OPID validation in Sec.  191.22(b), notifications 
in Sec.  191.22(c), and safety-related condition reports in Sec.  
191.23. Operators must still update their OPID information (e.g., 
change in primary entity, change in name) before submitting an incident 
or annual report if a change has occurred.

Sec.  191.3 Definitions

    PHMSA is adding definitions for ``regulated onshore gathering'' and 
``reporting-regulated gathering.'' The term ``regulated onshore 
gathering'' is defined as a Type A, Type B, or Type C gas gathering 
line as determined in accordance with Sec.  192.8. The term 
``reporting-regulated gathering'' is defined as an onshore gathering 
pipeline other than a regulated onshore gathering pipeline. These 
pipelines have been designated as ``Type R'' gathering lines in Sec.  
192.8 but are not regulated under that part.

Sec.  191.15 Transmission Systems; Gathering Systems; Liquefied Natural 
Gas Facilities; and Underground Natural Gas Storage Facilities: 
Incident Report

    This revision requires operators of Type R gathering pipelines to 
submit incident reports using DOT Form PHMSA F 7100.2-2. Regulated 
gathering lines, including Type C gathering lines, must continue to 
submit reports using DOT Form PHMSA F 7100.2.
    For Type R gathering lines, an incident report is required for any 
event meeting the definition of an incident that occurs after the 
effective date of the rule. Operators are not required to categorize 
and report retroactively events which occurred before the effective 
date of the rule. The form excludes information related to part 192 
requirements that do not apply.

Sec.  191.17 Transmission Systems; Gathering Systems; Liquefied Natural 
Gas Facilities; and Underground Natural Gas Storage Facilities: Annual 
Report

    This section prescribes requirements for submitting annual reports. 
This final rule adds a paragraph (a)(2) that specifies the annual 
reporting requirements for operators of Type R gathering lines. Such 
operators must complete and submit DOT Form PHMSA F 7100.2-3. The first 
report is due no later than March 15, 2023 for the 2022 reporting year. 
The form instructions address how to report data attributes that are 
unknown.

Sec.  191.23 Reporting Safety-Related Conditions

    This section specifies requirements for submitting safety-related 
conditions. In this final rule, paragraph (b)(1) is revised to except 
Type R gathering lines from safety-related condition reporting 
requirements in Sec. Sec.  191.23 and 191.25.

Sec.  191.29 National Pipeline Mapping System

    Section 191.29 specifies requirements for participation in the 
National Pipeline Mapping System (NPMS). Section 60132 of the Federal 
Pipeline Safety Law requires operators of a pipeline facilities 
excluding distribution and gathering lines to provide information to be 
included in the NPMS. In response to comments, the final rule clarifies 
that the requirements in Sec.  191.29 do not apply to gas gathering 
lines. Although Sec.  191.29(a) states the requirement applies only to 
operators of gas transmission lines and liquefied natural gas (LNG) 
facilities, the final rule makes the exclusion of gas gathering lines, 
including regulated onshore gas gathering lines, more explicit.

Sec.  192.3 Definitions

    Section 192.3 defines certain terms used in part 192. The final 
rule adds a definition for ``composite materials.'' The term 
``composite materials'' means the materials used to make pipes or 
components manufactured with a combination of either steel and/or 
plastic and a reinforcing material to maintain their circumferential or 
longitudinal strength. This definition is added to describe the process 
for notifying PHMSA prior to the use of composite materials on new, 
replaced, relocated, or otherwise changed Type C gathering lines in 
Sec.  192.9. This definition alone does not authorize the use of 
composite pipe or materials under this part.

Sec.  192.8 How are onshore gathering lines and regulated onshore 
gathering lines determined?

    Section 192.8 describes how onshore pipelines and segments are 
determined to be onshore gathering lines and regulated onshore 
gathering lines. The definition of regulated onshore gathering line has 
been redesignated as paragraph (c). The final rule adds a new paragraph 
(b) to specify that gas gathering line must maintain records 
documenting the methodology used to determine the beginning and 
endpoints of segments determined to be gas gathering lines as 
determined in accordance with part 192. This final rule specifies that 
these records must be established within 1 year of the effective date 
of the rule, or within 1 year of pipeline installation, whichever is 
later. These records include the API RP 80 definitions and methods used 
to define the beginning and endpoints and where those points are 
located (e.g., mile markers, address, or coordinates). Operators must 
maintain these records for the life of the pipeline, meaning until the 
pipeline is removed from the ground or permanently abandoned in place 
in accordance with Sec.  192.727. An operator may request an 
alternative compliance deadline with a notification to PHMSA submitted 
in accordance with Sec.  192.18 if the standard compliance deadline is 
impracticable. This notification must include a description of the 
affected facilities and operating environment, the justification for an 
alternative compliance deadline, and the operator's proposed 
alternative deadline. This notification must be submitted to PHMSA no 
later than 90 days prior to the standard compliance deadline in Sec.  
192.8(b)(1). The operator

[[Page 63288]]

may proceed with their proposed alternative deadline if they receive a 
no objection letter from PHMSA or if PHMSA has not replied within 90 
days of submitting the notification.
    The final rule also revises Sec.  192.8(a)(5) to address the use of 
the incidental gathering concept described in API RP 80. For new, 
replaced, relocated, or otherwise changed gas gathering lines installed 
after the effective date of this final rule, the ``incidental 
gathering'' concept, as described in section 2.2.1.2.6 of API RP 80, 
may not be used if the ``incidental'' endpoint in paragraph 
2.2(a)(1)(E) of API RP 80 is 10 miles or more from the furthermost 
downstream point where a gathering line end as determined in accordance 
with paragraphs 2.2 (a)(1)(A) through (a)(1)(D) of API RP 80 and Sec.  
192.8 (e.g. processing facilities, compressor stations, points of 
comingling). A new, replaced, relocated, or otherwise changed pipeline 
that is designated as an ``incidental gathering'' pipeline in API RP 80 
but is 10 miles or more in length will be considered a transmission 
pipeline subject to all applicable portions of parts 191 and 192. 
Incidental gathering lines existing on or before the effective date of 
the rule may continue to operate as a gathering line, regardless of 
length.
    One major aspect of this final rule is to identify a new category 
of regulated onshore gas gathering lines, designated as Type C lines in 
Sec.  192.8. As discussed previously, a Type C regulated onshore 
gathering line is defined as any onshore gathering line that is 8.625 
inches or larger in outside diameter, is located in a Class 1 location, 
and meets one of the following criteria, as applicable.
     Metallic pipe and the MAOP produces a hoop stress of 20 
percent or more of SMYS;
     Metallic pipe and, if the stress level is unknown, the 
MAOP is more than 125 psig (862 kPa); or
     Non-metallic and the MAOP is more than 125 psig (862 kPa).
    The minimum safety standards applicable to Type C gathering lines 
are specified in the revisions to Sec.  192.9. The final rule adds the 
new Type C category to the table in Sec.  192.8(b)(2). The purpose of 
adding this new category of regulated gas gathering lines is to ensure 
that operators of larger-diameter, higher-pressure gas gathering lines 
in Class 1 locations follow a basic set of requirements targeting known 
threats to public safety and pipeline integrity such as excavation 
damage, corrosion, and construction defects.

Sec.  192.9 What requirements apply to gathering lines?

    This final rule codifies the minimum safety standards for Type C 
regulated gas gathering lines. The requirements for Type C gathering 
lines in this final rule are broken down as follows:
    Type C requirements for pipelines with outside diameter of 8.625 
inches and greater:
     Design, installation, construction, and initial inspection 
and testing per transmission line requirements in part 192 for lines 
that are new, replaced, relocated, or otherwise changed after the 
applicable compliance date in Sec.  192.13;
     Corrosion control (part 192, subpart I);
     Damage prevention program (Sec.  192.614);
     Emergency plans (Sec.  192.615);
     Public awareness (Sec.  192.616);
     Line markers (Sec.  192.707); and
     Leakage surveys (Sec.  192.706).
    Additional Type C requirements for pipelines with an outside 
diameter of 12.75 inches and greater:
     Applicable requirements of part 192 for plastic pipe and 
components; and
     Establish MAOP (Sec.  192.619).
    The final rule adds Sec.  192.9(f), which creates an exception from 
certain part 192 requirements if a Type C gathering line has a diameter 
of 16 inches or less and is not located near local communities as 
determined by one of the following methods:
    Method 1. Potential Impact Circle. The segment is not located 
within a potential impact circle as defined in Sec.  192.903 containing 
a building intended for human occupancy or other impacted site. This is 
the same method used to determine HCAs in the gas transmission 
integrity management regulations. Note that similar to the method for 
identifying HCAs, any point on a pipeline located within any potential 
impact circle containing a building intended for human occupancy or 
other impacted site may not apply the exception even if a potential 
impact circle drawn from that point does not contain such a location 
itself (Refer to Figure E.I.A. in appendix E to part 192).
    The formula for calculating a potential impact radius is defined in 
Sec.  192.903. PHMSA notes that this formula requires knowledge of the 
MAOP and nominal diameter of the pipeline. If the segment does not have 
an MAOP established in accordance with Sec.  192.619, or if the 
diameter is unknown, the operator must use method 2 or not apply the 
exception and comply with the Type C requirements that are applicable 
based on the diameter of the pipeline. Additionally, operators must use 
a factor of 0.73 rather than the dry gas factor of 0.69 used in the 
integrity management regulations. The increased factor accounts for the 
potentially higher combustion energy of unprocessed natural gas, which 
may contain varying amounts of other combustible hydrocarbons.
    Method 2: Class Location Unit. This analysis is similar to Method 
1. However instead of calculating a potential impact circle, the class 
location unit as defined in Sec.  192.5(a)(1) is used. This is the 
``sliding mile'' or ``continuous-mile'' analysis used for class 
location determination. A class location unit is 1 mile in length and 
extends 220 yards on either side of the centerline of a pipeline. PHMSA 
notes that this uses the same ``sliding mile'' approach used for 
determining class location rather than static mile-long increments 
stacked end-over-end. The class-location unit moves along the pipeline, 
and if the sliding mile contains a building intended for human 
occupancy or other impacted site at any point during the mile's 
movement, then the exception in paragraph (f) does not apply for the 
entire mile of pipeline contained within the sliding mile. This method 
does not require knowledge of the pipeline's MAOP.
    For the purposes of applying this exception, ``building intended 
for human occupancy'' or ``other impacted site'' is defined in Sec.  
192.9(f)(4) to mean any of the following:
     One or more buildings that may be occupied by humans, 
including homes, office buildings factories, outside recreation areas, 
and plant facilities.
     A small, well-defined outside area (such as a playground, 
recreation area, outdoor theater, or other place of public assembly) 
that is occupied by 20 or more persons on at least 5 days a week for 10 
weeks in any 12-month period (the days and weeks need not be 
consecutive). This has the same meaning and interpretation as the Class 
3 criterion in Sec.  192.5(b)(3)(ii); or
     Any portion of the paved surface, including shoulders, of 
a designated interstate, other freeway, or expressway, as well as any 
other principal arterial roadway with 4 or more lanes. This has the 
same meaning and interpretation of section (1)(ii) of the ``moderate 
consequence area'' definition in Sec.  192.3.
    The table below summarizes the applicability of the Type C 
requirements based on the size and location of a given segment.

[[Page 63289]]

------------------------------------------------------------------------
                               Not located near a      Located near a
                                building intended     building intended
                               for human occupancy   for human occupancy
      Outside diameter          or other impacted     or other impacted
                                   site (Sec.            site (Sec.
                                    192.9(f))             192.9(f))
------------------------------------------------------------------------
Greater than or equal to      --Design,             --Design,
 8.625 inches up to and        Construction,         Construction,
 including 12.75 inches.       Initial Testing       Initial Testing
                               (new/replaced/        (new/replaced/
                               relocated/changed     relocated/changed
                               lines).               lines).
                              --Damage Prevention.  --Corrosion Control.
                              --Emergency plans...  --Damage Prevention.
                                                    --Emergency Plans.
                                                    --Line Markers.
                                                    --Public Awareness.
                                                    --Leakage Surveys.
Greater than 12.75 inches up  --Design,             All Type C
 to and including 16 inches.   Construction,         Requirements.
                               Initial Testing
                               (new/replaced/
                               relocated/changed
                               lines).
                              --Damage Prevention.
                              --Emergency Plans.
Greater than 16 inches......  All Type C            All Type C
                               Requirements.         Requirements.
------------------------------------------------------------------------

    Section 60104(b) of the Pipeline Safety Acts exempts new design, 
installation, construction, initial inspection, and initial testing 
standards from applying to gathering lines that existed before the 
effective date of this final rule. In other words, if a previously 
unregulated gas gathering line becomes regulated by operation of this 
final rule (and is not itself replaced, relocated, or otherwise changed 
after the compliance date in Sec.  192.13), the operator is not 
required to bring retroactively that pipeline facility into compliance 
with the new design, installation, construction, initial inspection, 
and initial testing requirements.
    The rule also adds an exception in Sec.  192.9(f)(3) to these 
requirements for segments shorter than 40 feet \78\ that are installed, 
relocated, or changed on Type C gathering lines that were installed 
before the effective date of the rule. Regulations in part 192 that do 
not pertain to design, installation, construction, initial 
installation, or initial testing may apply to the segment regardless of 
the date of installation.
---------------------------------------------------------------------------

    \78\ A single length of pipe is typically 40 feet in length.
---------------------------------------------------------------------------

    In Sec.  192.9(g)(4), existing gathering lines that become 
classified as Type C regulated gathering lines due to the publication 
of this final rule have a 1-year compliance deadline to meet the 
applicable requirements in this section. An operator may request an 
alternative compliance deadline with a notification to PHMSA submitted 
in accordance with Sec.  192.18 if the standard compliance deadline is 
impracticable. This notification must include a description of the 
affected facilities and operating environment and, for each requirement 
that requires an alternative compliance deadline: The justification for 
an alternative compliance deadline, and the operator's proposed 
alternative deadline. The notification must also include a description 
of actions the operator will take to ensure the safety of the affected 
facilities in the interim. This notification must be submitted no later 
than 90 days prior to the standard compliance deadline. The operator 
may proceed with their proposed alternative deadline if they receive a 
no objection letter from PHMSA or if PHMSA has not replied within 90 
days of submitting the notification.
    In Sec.  192.9(g)(5), operators of gathering lines that become 
classified as Type C regulated gathering lines in the future due to an 
increase in MAOP, a change in dwelling density, or a change in class 
location have a 1-year compliance deadline to meet the requirements of 
this section. Similarly, an operator of a Type C gathering line that 
becomes subject to additional Type C requirements in the future, for 
example when a change in dwelling density or increased MAOP causes the 
exceptions in paragraph (f) to no longer apply, has a 1-year compliance 
deadline to meet those additional requirements. Conforming changes were 
made to paragraphs (g)(2) and (3) to clarify that the existing 
implementation deadlines now apply only to Type A and Type B regulated 
gathering lines.
    The final rule also adds a new paragraph (h) to clarify that 
operators may install or replace pipe or components made of composite 
materials that are not otherwise authorized in part 192 on Type C 
gathering lines upon submittal of a notification to PHMSA pursuant to 
Sec.  192.18, unless PHMSA issues an objection letter to the operator's 
notification. Under the Sec.  192.18 notification process, PHMSA will 
evaluate the operator's proposed operation and maintenance procedures, 
which includes the operator's proposed remediation methods and 
procedures for identifying defects and determining the safe operating 
pressures of composite pipe when defects are found. PHMSA will not 
approve notifications that are not consistent with pipeline safety. A 
rejection under Sec.  192.18 will not foreclose an operator's ability 
to seek a special permit in accordance with Sec.  190.341.
    Operators may continue to operate gathering lines containing 
composite pipe or materials existing on or before the effective date of 
the rule without notification to PHMSA. However, operators of Type C 
pipelines must comply with all other applicable Type C requirements 
once the final rule becomes effective. Additionally, per new Sec.  
192.9(e)(1)(i), notification is not required for replacements, 
relocations, or changes of composite pipe segments 40 feet or less in 
length on pipelines that were installed before the effective date of 
the rule. Replacements using composite materials on Type C gathering 
lines, including composite materials installed per a notification, 
require notification to PHMSA regardless of length. Replacing a segment 
of composite pipe with steel or plastic pipe and components authorized 
under part 192 does not require notification. The notification 
requirement does apply to repairs involving replacements, relocations, 
or significant changes to the pipe. If an operator discovers a 
condition that requires immediate replacement, operators should 
describe all urgent conditions in their notification to PHMSA, request 
an emergency special permit under Sec.  190.341, or conduct the repair 
using materials authorized under part 192, such as steel.

Sec.  192.13 What general requirements apply to pipelines regulated 
under this part?

    This is a conforming change that repeats the compliance deadlines 
for Type C lines in Sec.  192.8 and clarifies that the previously 
existing compliance deadlines for regulated gas gathering lines in that 
section continue to apply

[[Page 63290]]

to Type A and Type B regulated gathering lines.

Sec.  192.18 How To Notify PHMSA

    This is a conforming change in the final rule to allow the use of 
the notification procedures in this section to comply with Sec. Sec.  
192.8(b) and (g)(4), 192.9(h), and 192.619(c)(2).

Sec.  192.150 Passage of Internal Inspection Devices

    Currently, this section provides that Type A regulated gathering 
lines are exempt from the requirement that new gas transmission lines 
be able to accommodate the passage of instrumented internal inspection 
devices. This amendment clarifies that lower-risk Type B and Type C 
lines are also exempt.

Sec.  192.452 How does this subpart apply to converted pipelines and 
regulated onshore gathering lines?

    This section of the final rule documents conforming changes to 
address the applicability of part 192, subpart I, to unregulated 
gathering lines that become Type C onshore regulated gathering lines. 
Specifically, it covers previously unregulated gathering lines that 
become regulated by operation of this final rule. Additionally, it 
covers previously unregulated gathering lines that become subject to 
Type C corrosion control requirements in the future due to a change in 
MAOP or the presence of a building intended for human occupancy or 
other impacted site. Such pipelines are treated as if they were 
installed before August 1, 1971, for the purposes of subpart I. The 
final rule also clarifies in paragraph (d) that gathering lines that 
are subject to subpart I at the time of construction must meet the 
corrosion control requirements applicable to pipelines installed after 
July 31, 1971.

Sec.  192.619 Maximum Allowable Operating Pressure: Steel or Plastic 
Pipelines

    This section of the final rule includes conforming changes on the 
applicability of Sec.  192.619 for determining the MAOP for newly 
regulated gathering lines, i.e., Type C lines. Additionally, a new 
paragraph (c)(2) has been added to allow operators of newly regulated 
Type C gas gathering lines to establish an MAOP using ``other 
technology'', upon notification to PHMSA in accordance with Sec.  
192.18. This process would only be available to segments where the MAOP 
was established under Sec.  192.619(c) and the operator does not have 
the requisite operational pressure records because the pipeline was 
previously unregulated and not required to retain such records. The 
justification of the proposed MAOP must be reviewed and accepted by a 
qualified technical subject matter expert. PHMSA expects a qualified 
subject matter expert to be an individual with formal or on-the-job 
technical training in the technical or operational area being analyzed, 
evaluated, or assessed. The operator must be able to document that the 
individual is appropriately knowledgeable and experienced in the 
subject being assessed.

V. Availability of Standards Incorporated by Reference

    PHMSA currently incorporates by reference into 49 CFR parts 192, 
193, and 195 all or parts of more than 80 standards and specifications 
developed and published by standard development organizations (SDO). In 
general, SDOs update and revise their published standards every 2 to 5 
years to reflect modern technology and best technical practices. 
Sometimes multiple editions are published in a given year.
    The National Technology Transfer and Advancement Act of 1995 
(NTTAA, Pub. L. 104-113) directs Federal agencies to use standards 
developed by voluntary consensus standards bodies in lieu of 
government-written standards whenever possible. Voluntary consensus 
standards bodies develop, establish, or coordinate technical standards 
using agreed-upon procedures. In addition, OMB issued Circular A-119 to 
implement section 12(d) of the NTTAA relative to the utilization of 
consensus technical standards by Federal agencies.\79\ This circular 
provides guidance for agencies participating in voluntary consensus 
standards bodies and describes procedures for satisfying the reporting 
requirements in the NTTAA.
---------------------------------------------------------------------------

    \79\ 81 FR 4673 (Jan. 27, 2016).
---------------------------------------------------------------------------

    Accordingly, PHMSA has the responsibility for determining, via 
petitions or otherwise, which currently referenced standards should be 
updated, revised, or removed, and which standards should be added to 
the Federal Pipeline Safety Regulations. Revisions to materials 
incorporated by reference in the Federal Pipeline Safety Regulations 
are handled via the rulemaking process, which allows for the public and 
regulated entities to provide input. During the rulemaking process, 
PHMSA must also obtain approval from the Office of the Federal Register 
to incorporate by reference any new materials.
    Pursuant to 49 U.S.C. 60102(p), PHMSA may not issue amendments to 
the Federal Pipeline Safety Regulations that incorporate by reference 
any documents or portions thereof unless the documents or portions 
thereof are made available to the public, free of charge. Further, the 
Office of the Federal Register issued a rulemaking on November 7, 2014, 
revising 1 CFR 51.5(b) to require that agencies detail in the preamble 
of a final rule how the materials being incorporated by reference are 
reasonably available to interested parties, and how interested parties 
can obtain those materials.\80\
---------------------------------------------------------------------------

    \80\ Incorporation by Reference, 79 FR 66278.
---------------------------------------------------------------------------

    The only standard incorporated by reference in the final rule is 
API RP 80. Free, online, read-only access to API RP 80 is available on 
the API website (http://publications.api.org/AccessToDocuments.aspx; 
navigate to the ``Exploration and Production'' category). Members of 
the public interested in obtaining API RP 80 can contact API using the 
contact information in this final rule's revisions to the regulatory 
text at Sec.  192.7. In addition, PHMSA will provide individual members 
of the public temporary access to this or any other standard that is 
incorporated by reference in the Federal Pipeline Safety Regulations. 
Requests for access can be sent to the following email address: 
[email protected].

VI. Regulatory Analysis and Notices

A. Statutory/Legal Authority for This Rulemaking

    This final rule is published under the authority of Federal 
Pipeline Safety Law. Section 60101(b) authorizes the Secretary of 
Transportation to prescribe standards defining the term ``gathering 
line'' that account for the functional and operational characteristics 
of a pipeline. That section also authorizes the Secretary to prescribe 
standards defining the term ``regulated gathering line,'' which must 
consider factors such as location, length of line from the well site, 
operating pressure, throughput, and the composition of the transported 
gas. In addition, 49 U.S.C. 60102 authorizes the Secretary to issue 
regulations governing design, installation, inspection, emergency plans 
and procedures, testing, construction, extension, operation, 
replacement, and maintenance of pipeline facilities. Further, 49 U.S.C. 
60117(b)(2) authorizes the Secretary to require owners and operators of 
gathering lines to submit information pertinent to the Secretary's 
ability to make a determination as to whether and to what extent to 
regulate gathering lines. The

[[Page 63291]]

Secretary delegated his authority to the PHMSA Administrator under 49 
CFR 1.97.

B. Executive Order 12866 and DOT Regulatory Policies and Procedures

    Executive Order 12866 (``Regulatory Planning and Review'') \81\ 
requires that agencies ``should assess all costs and benefits of 
available regulatory alternatives, including the alternative of not 
regulating.'' Agencies should consider quantifiable measures and 
qualitative measures of costs and benefits that are difficult to 
quantify. Further, Executive Order 12866 requires that ``agencies 
should select those [regulatory] approaches that maximize net benefits 
(including potential economic, environmental, public health and safety, 
and other advantages; distributive impacts; and equity), unless a 
statute requires another regulatory approach.'' Similarly, DOT Order 
2100.6A (``Rulemaking and Guidance Procedures'') requires that 
regulations issued by PHMSA and other DOT Operating Administrations 
should consider an assessment of the potential benefits, costs, and 
other important impacts of the proposed action and should quantify (to 
the extent practicable) the benefits, costs, and any significant 
distributional impacts, including any environmental impacts.
---------------------------------------------------------------------------

    \81\ 58 FR 51375 (Oct. 4, 1993).
---------------------------------------------------------------------------

    Executive Order 12866 and DOT Order 2100.6A require that PHMSA 
submit ``significant regulatory actions'' to the Office of Management 
and Budget (OMB) for review. This final rule has been determined to be 
significant under section 3(f) of Executive Order 12866 and was 
reviewed by OMB. It is also considered significant under DOT Order 
2100.6. The Office of Information and Regulatory Affairs (OIRA) has not 
designated this rule as a ``major rule'' as defined by the 
Congressional Review Act (5 U.S.C. 801 et seq.).
    Executive Order 12866 and DOT Order 2100.6A also require PHMSA to 
provide a meaningful opportunity for public participation, which 
reinforces requirements for notice and comment in the Administrative 
Procedure Act (APA, 5 U.S.C. 551 et seq.). In accord with the 
requirement, PHMSA sought public comment on the proposals in the NPRM 
(including preliminary cost and cost savings analyses pertaining to 
those proposals), as well as any information that could assist in 
evaluating the benefits and costs of this rulemaking. Those comments 
are addressed, and additional discussion about the economic impacts of 
the final rule are provided, within the final regulatory impact 
analysis (RIA) posted in the docket.
    PHMSA expects benefits of the final rule to consist of improved 
safety and avoided environmental harms (including greenhouse gas 
emissions) from reduction of risk of failures of onshore natural gas 
gathering lines due to improved leak detections and subsequent repairs. 
The expected benefits will depend on the degree to which compliance 
actions result in additional safety measures, relative to the baseline, 
and the effectiveness of these measures in preventing or mitigating 
future pipeline failures. PHMSA estimates annualized costs of $13.7 
million per year using a 7 percent discount rate. The costs for 
compliance with annual reporting and, for Type C gathering lines, 
compliance with part 192 are expected to be higher in the initial 
compliance period, as operators will incur one-time costs to achieve 
compliance in the years leading up to the compliance deadline. 
Thereafter recurring costs are expected to be lower. For more 
information, please see the RIA posted in the rulemaking docket.

C. Environmental Justice

    DOT Order 5610.2C and Executive Orders 12898 (``Federal Actions to 
Address Environmental Justice in Minority Populations and Low-Income 
Populations''),\82\ 13985 (``Advancing Racial Equity and Support for 
Underserved Communities Through the Federal Government''),\83\ 13990 
(``Protecting Public Health and the Environment and Restoring Science 
To Tackle the Climate Crisis''),\84\ and 14008 (``Tackling the Climate 
Crisis at Home and Abroad'') \85\ require DOT agencies to achieve 
environmental justice as part of their mission by identifying and 
addressing, as appropriate, disproportionately high and adverse human 
health or environmental effects, including interrelated social and 
economic effects, of their programs, policies, and activities on 
minority populations, low-income populations, and other disadvantaged 
communities.
---------------------------------------------------------------------------

    \82\ 59 FR 7629 (Feb. 16, 1994).
    \83\ 86 FR 7009 (Jan. 20, 2021).
    \84\ 86 FR 7037 (Jan. 20, 2021).
    \85\ 86 FR 7619 (Feb. 1, 2021).
---------------------------------------------------------------------------

    PHMSA has evaluated this final rule under DOT Order 5610.2C and the 
Executive orders listed above and has determined it would not cause 
disproportionately high and adverse human health and environmental 
effects on minority populations, low-income populations, or other 
underserved and disadvantaged communities. The rulemaking is facially 
neutral and national in scope; it is neither directed toward a 
particular population, region, or community, nor is it expected to 
adversely impact any particular population, region, or community. And 
insofar as PHMSA expects the rulemaking would reduce the safety and 
environmental risks associated with onshore natural gas gathering 
lines, many of which are located in the vicinity of environmental 
justice communities,\86\ PHMSA does not expect the regulatory 
amendments introduced by this final rule would entail 
disproportionately high adverse risks for minority populations, low-
income populations, or other underserved and other disadvantaged 
communities in the vicinity of those pipelines. Lastly, as explained in 
final environmental assessment (EA), PHMSA expects that the regulatory 
amendments in this final rule will yield greenhouse gas emissions 
reductions, thereby reducing the risks posed by anthropogenic climate 
change to minority, low-income, underserved, and other disadvantaged 
populations and communities.
---------------------------------------------------------------------------

    \86\ See Ryan Emmanuel, et al., ``Natural Gas Gathering and 
Transmission Pipelines and Social Vulnerability in the United 
States,'' 5:6 GeoHealth (June 2021), https://agupubs.onlinelibrary.wiley.com/toc/24711403/2021/5/6 (concluding 
that natural gas gathering and transmission infrastructure is 
disproportionately sited in socially-vulnerable communities).
---------------------------------------------------------------------------

D. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA, 5 U.S.C. 601 et seq.) requires 
Federal regulatory agencies to prepare a Final Regulatory Flexibility 
Analysis (FRFA) for any final rule subject to notice-and-comment 
rulemaking under the APA unless the agency head certifies that the rule 
will not have a significant economic impact on a substantial number of 
small entities. This final rule was developed in accordance with 
Executive Order 13272 (``Proper Consideration of Small Entities in 
Agency Rulemaking'') \87\ to promote compliance with the RFA and to 
ensure that the potential impacts of the rulemaking on small entities 
has been properly considered.
---------------------------------------------------------------------------

    \87\ 67 FR 53461 (Aug. 16, 2002).
---------------------------------------------------------------------------

    PHMSA does not have access to firm-level data on gathering line 
operators that are not currently regulated under part 191 or 192. 
However, based on data on regulated gathering line operators produced 
by Dun and Bradstreet, approximately 40 percent of currently regulated 
gathering line operators are identified as small entities, and those 
entities operate approximately 24 percent of onshore regulated gas 
gathering line mileage. Therefore, a

[[Page 63292]]

significant share of affected entities can be classified as small 
entities. However, PHMSA expects the magnitude of the economic impact 
on those entities to be limited, as the annualized costs of the final 
rule represent only approximately 0.1 percent of annual industry 
revenues for the entire crude oil transportation industry (NAICS code 
486110), illustrating the minor financial impact on firms operating 
within this space. PHMSA has prepared a FRFA, available in the docket 
for the rulemaking, in which PHMSA certifies that the rule will not 
have a significant impact on a substantial number of small entities.

E. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    PHMSA analyzed this final rule in accordance with the principles 
and criteria in Executive Order 13175 (``Consultation and Coordination 
with Indian Tribal Governments'') \88\ and DOT Order 5301.1 
(``Department of Transportation Programs, Polices, and Procedures 
Affecting American Indians, Alaska Natives, and Tribes''). Executive 
Order 13175 requires agencies to assure meaningful and timely input 
from Tribal government representatives in the development of rules that 
significantly or uniquely affect Tribal communities by imposing 
``substantial direct compliance costs'' or ``substantial direct 
effects'' on such communities or the relationship and distribution of 
power between the Federal Government and Tribes.
---------------------------------------------------------------------------

    \88\ 65 FR 67249 (Nov. 6, 2000).
---------------------------------------------------------------------------

    PHMSA assessed the impact of the rulemaking and determined that it 
would not significantly or uniquely affect Tribal communities or Indian 
Tribal governments. The rulemaking's regulatory amendments are facially 
neutral and would have broad, national scope; PHMSA, therefore, does 
not expect this rulemaking to significantly or uniquely affect Tribal 
communities, much less impose substantial compliance costs on Native 
American Tribal governments or mandate Tribal action. And insofar as 
PHMSA expects the rulemaking will improve natural gas gathering line 
safety and reduce environmental risks, PHMSA does not expect it would 
entail disproportionately high adverse risks for Tribal communities. 
PHMSA also received no comments alleging ``substantial direct 
compliance costs'' or ``substantial direct effects'' on Tribal 
communities and Governments. For these reasons, PHMSA has determined 
the funding and consultation requirements of Executive Order 13175 and 
DOT Order 5301.1 do not apply.

F. Paperwork Reduction Act

    Pursuant to 5 CFR 1320.8(d), PHMSA is required to provide 
interested members of the public and affected agencies with an 
opportunity to comment on information collection and recordkeeping 
requests. PHMSA expects this final rule to impact the information 
collections described below.
    PHMSA will submit an information collection revision request to OMB 
for approval based on the requirements in this final rule. The 
information collections are contained in the pipeline safety 
regulations, 49 CFR parts 190 through 199. The following information is 
provided for each information collection: (1) Title of the information 
collection; (2) OMB control number; (3) Current expiration date; (4) 
Type of request; (5) Abstract of the information collection activity; 
(6) Description of affected public; (7) Estimate of total annual 
reporting and recordkeeping burden; and (8) Frequency of collection. 
The information collection burdens for the following information 
collections are estimated to be revised as follows:
    1. Title: Recordkeeping Requirements for Gas Pipeline Operators.
    OMB Control Number: 2137-0049.
    Current Expiration Date: 01/31/2023.
    Abstract: A person owning or operating a natural gas pipeline 
facility is required to maintain records, make reports, and provide 
information to the Secretary of Transportation at the Secretary's 
request. This mandatory information collection request would require 
owners and/or operators of gas pipeline systems to make and maintain 
records in accordance with the requirements prescribed in 49 CFR part 
192 and to provide information to the Secretary of Transportation at 
the Secretary's request. Certain records are maintained for a specific 
length of time while others are required to be maintained for the life 
of the pipeline. PHMSA uses these records to verify compliance with 
regulated safety standards and to inform the agency on possible safety 
risks.
    Based on the provisions in the Safety of Gas Gathering Pipelines: 
Extension of Reporting Requirements, Regulation of Large, High-Pressure 
Lines, and Other Related Amendments final rule, PHMSA estimates that 
370 new Type C gas gathering pipeline operators ~ (91,000 Type C miles 
w/o prior regulation) will be subject to these requirements. PHMSA 
estimates that it will take these 370 operators 6 hours to create and 
maintain records associated with 49 CFR 192.9 requirements. Therefore, 
PHMSA expects to add 370 responses and 2,220 hours to this information 
collection as a result of the provisions in this final rule.
    Affected Public: Natural Gas Pipeline Operators.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 3,861,842.
    Total Annual Burden Hours: 1,677,030.
    Frequency of Collection: On occasion.
    2. Title: Annual and Incident Reports for Gas Pipeline Operators.
    OMB Control Number: 2137-0522.
    Current Expiration Date: 10/31/2024.
    Abstract: This mandatory information collection covers the 
collection of annual and immediate notice of incident report data from 
Gas pipeline operators. As a result of the Safety of Gas Gathering 
Pipelines: Extension of Reporting Requirements, Regulation of Large, 
High-Pressure Lines, and Other Related Amendments final rule, all gas 
gathering operators will become subject to incident and annual 
reporting requirements. PHMSA is revising this information collection 
to account for the new addition to the reporting community. PHMSA will 
require 500 currently unregulated gas gathering line operators (370 
Type C operators and 130 Type R operators) to complete and submit 
annual reports each year. Type C operators will submit annual report 
data on DOT Form PHMS F7 100.2-1. The estimated burden for submitting 
this form is 47 hours per report. Type R operators will submit annual 
report data on the new DOT Form PHMSA F7 100.2-3. The estimated burden 
for submitting this form is 21 hours per report. These changes will 
result in an overall annual burden increase of 20,120 hours (17,390 
hours annually for Type C operators and 2,730 hours annually for Type R 
operators) for this information collection.
    Gas Gathering operators will also be required to make immediate 
telephonic notification of incidents, should they occur. PHMSA expects 
that these previously unregulated operators will make approximately 85 
telephonic notifications of incidents per year. PHMSA estimates that it 
takes 30 minutes to complete a telephonic notification. As such, the 
estimated burden for gas gathering operators to make immediate 
notification of incidents is approximately 43 hours.
    As a result of the provisions mentioned above, the burden for this 
information collection will increase by 585 new responses and 10,543 
burden hours.
    Affected Public: Natural Gas Pipeline Operators.

[[Page 63293]]

    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 2,832.
    Total Annual Burden Hours: 91,964.
    Frequency of Collection: Annually and on occasion.
    3. Title: Incident Reports for Natural Gas Pipeline Operators.
    OMB Control Number: 2137-0635.
    Current Expiration Date: 10/31/2024.
    Abstract: Operators of natural gas pipelines and LNG facilities are 
required to report incidents, on occasion, to PHMSA per the 
requirements in 49 CFR part 191. This mandatory information collection 
covers the collection of incident report data from natural gas pipeline 
operators. The reports contained within this information collection 
support the Department of Transportation's strategic goal of safety. 
This information is an essential part of PHMSA's overall effort to 
minimize natural gas transmission, gathering, and distribution pipeline 
failures. Due to the provisions contained within the Safety of Gas 
Gathering Pipelines: Extension of Reporting Requirements, Regulation of 
Large, High-Pressure Lines, and Other Related Amendments final rule, 
operators will be required to submit reports of incidents that occur on 
previously unregulated gas gathering systems.
    Based on PHMSA's estimate of the mileage of Type C and Type R gas 
gathering pipelines and the incident rate on Type A and Type B gas 
gathering pipelines, PHMSA expects to receive approximately 85 incident 
reports (18 Type C incident reports and 67 Type R incident reports) 
each year from gas gathering operators. As a result, the burden for 
this information collection will increase by 85 responses. The burden 
per incident report is estimated at 12 hours per report. This results 
in an estimated burden increase of 1,020 hours (216 hours for Type C 
and 804 hours for Type R) per year.
    Affected Public: Natural Gas Pipeline Operators.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 344.
    Total Annual Burden Hours: 4,128.
    Frequency of Collection: On occasion.
    4. Title: National Registry of Pipeline and LNG Operators.
    OMB Control Number: 2137-0627.
    Current Expiration Date: 01/31/2023.
    Abstract: The National Registry of Pipeline and LNG Operators 
serves as the storehouse for the reporting requirements for an operator 
regulated or subject to reporting requirements under 49 CFR part 192, 
193, or 195. This mandatory information collection would require 
jurisdictional pipeline operators to submit the required data to 
register with the National Registry of Pipeline and LNG Operators and 
notify PHMSA when they experience significant asset changes, including 
new construction, that affect PHMSA's ability to accurately monitor and 
assess pipeline safety performance. Certain types of changes to, or 
within, an operator's facilities or pipeline network represent 
potential safety-altering activities for which PHMSA may need to 
inspect, investigate, or otherwise oversee to ensure that any public 
safety concerns are adequately and proactively addressed. The forms for 
assigning and maintaining Operator Identification (OPID) information 
are the Operator Assignment Request Form (PHMSA F 1000.1) and Operator 
Registry Notification Form (PHMSA F 1000.2). The purpose of this 
information collection is to maintain an accurate assessment of the 
Nation's pipeline infrastructure and to be kept abreast of conditions 
that could potentially compromise the safety and economic viability of 
the U.S. pipeline system.
    Due to the provisions contained within the Safety of Gas Gathering 
Pipelines: Extension of Reporting Requirements, Regulation of Large, 
High-Pressure Lines, and Other Related Amendments final rule, gas 
gathering pipeline operators must now request OPIDs due to the repeal 
of the reporting exception for gathering pipelines other than regulated 
gathering lines as determined in Sec.  192.8. PHMSA plans to revise the 
OPID Registry form and instructions to account for this addition to the 
reporting community. PHMSA believes that many operators of previously 
unregulated gathering lines are already submitting annual report data 
for regulated gas gathering lines and may already have an OPID. As 
such, PHMSA expects to receive approximately 13 new OPID requests. 
PHMSA also requires these newly regulated operators to submit 
notifications to PHMSA in certain instances. PHMSA similarly expects to 
receive approximately 13 new notifications from gas gathering pipeline 
operators. These additions will result in an increase to the burden of 
this information collection by 26 responses and 26 burden hours.
    Affected Public: Operators of Natural Gas, Hazardous Liquid, and 
Liquefied Natural Gas pipelines.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 744.
    Total Annual Burden Hours: 744.
    Frequency of Collection: On occasion.
    Requests for copies of these information collections should be 
directed to Angela Hill or Cameron Satterthwaite, Office of Pipeline 
Safety (PHP-30), Pipeline Hazardous Materials Safety Administration 
(PHMSA), 2nd Floor, 1200 New Jersey Avenue SE, Washington, DC 20590-
0001, Telephone (202) 366-1246.

G. Unfunded Mandates Reform Act of 1995

    The Unfunded Mandates Reform Act (UMRA, 2 U.S.C. 1501 et seq.) 
requires agencies to assess the effects of Federal regulatory actions 
on State, local, and Tribal governments, and the private sector. For 
any NPRM or final rule that includes a Federal mandate that may result 
in the expenditure by State, local, and Tribal governments, in the 
aggregate of $100 million or more (in 1996 dollars) in any given year, 
the agency must prepare, amongst other things, a written statement that 
qualitatively and quantitatively assesses the costs and benefits of the 
Federal mandate. PHMSA prepared a final RIA and determined that this 
final rule does not impose enforceable duties on State, local, or 
Tribal governments or on the private sector of $100 million or more (in 
1996 dollars) in any one year. A copy of the RIA is available for 
review in the docket of this rulemaking.

H. National Environmental Policy Act

    The National Environmental Policy Act of 1969 (NEPA, 42 U.S.C. 4321 
et seq.) requires Federal agencies to consider the consequences of 
major Federal actions and prepare a detailed statement on actions 
significantly affecting the quality of the human environment. The 
Council on Environmental Quality implementing regulations (40 CFR parts 
1500-1508) require Federal agencies to conduct an environmental review 
considering (1) the need for the action, (2) alternatives to the 
action, (3) probable environmental impacts of the action and 
alternatives, and (4) the agencies and persons consulted during the 
consideration process. DOT Order 5610.1C (``Procedures for Considering 
Environmental Impacts'') establishes departmental procedures for 
evaluation of environmental impacts under NEPA and its implementing 
regulations.
    PHMSA has completed its NEPA analysis. Based on the environmental 
assessment, PHMSA determined that an environmental impact statement is 
not required for this rulemaking because it will not have a significant 
impact on the human environment. The final EA and Finding of No 
Significant Impact have been placed into the docket addressing the 
comments received.

[[Page 63294]]

I. Executive Order 13132: Federalism

    PHMSA analyzed this final rule in accordance with Executive Order 
13132 (``Federalism'').\89\ Executive Order 13132 requires agencies to 
assure meaningful and timely input by State and local officials in the 
development of regulatory policies that may have ``substantial direct 
effects on the States, on the relationship between the national 
government and the States, or on the distribution of power and 
responsibilities among the various levels of government.''
---------------------------------------------------------------------------

    \89\ 64 FR 43255 (Aug. 10, 1999).
---------------------------------------------------------------------------

    This final rule does not have a substantial direct effect on State 
and local governments, the relationship between the National Government 
and the States, or the distribution of power and responsibilities among 
the various levels of government. This rulemaking action does not 
impose substantial direct compliance costs on State and local 
governments. The final rule exercises PHMSA's existing authority to 
require operators of gas gathering line to submit safety data (49 
U.S.C. 60117(b)(2)) and to define and establish safety standards for 
regulated gas gathering lines (49 U.S.C. 60101(b)). PHMSA determined 
the final rule's changes to the requirements for onshore gas gathering 
lines were necessary based on the results of PHMSA's review of existing 
gas gathering requirements performed pursuant to section 21 of the 2011 
Pipeline Safety Act.
    Section 60104(c) of Federal Pipeline Safety Law prohibits certain 
State safety regulation of interstate pipelines. Under the pipeline 
safety laws, States that have submitted a current certification under 
section 60105(a) can augment Federal pipeline safety requirements for 
intrastate pipelines regulated by PHMSA but may not approve safety 
requirements less stringent than those required by Federal law. A State 
may also regulate an intrastate pipeline facility that PHMSA does not 
regulate.
    In this instance, the preemptive effect of the final rule is 
limited to the minimum level necessary to achieve the objectives of the 
Federal Pipeline Safety Law under which the final rule is promulgated. 
Therefore, the consultation and funding requirements of Executive Order 
13132 do not apply.

J. Executive Order 13211: Significant Energy Actions

    Executive Order 13211 (``Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use'') \90\ 
requires Federal agencies to prepare a Statement of Energy Effects for 
any ``significant energy action.'' Executive Order 13211 defines a 
``significant energy action'' as any action by an agency (normally 
published in the Federal Register) that promulgates, or is expected to 
lead to the promulgation of, a final rule or regulation that (1)(i) is 
a significant regulatory action under Executive Order 12866 or any 
successor order and (ii) is likely to have a significant adverse effect 
on the supply, distribution, or use of energy (including a shortfall in 
supply, price increases, and increased use of foreign supplies); or (2) 
is designated by the Administrator of the OIRA as a significant energy 
action.
---------------------------------------------------------------------------

    \90\ 66 FR 28355 (May 22, 2001).
---------------------------------------------------------------------------

    This final rule is a significant action under Executive Order 
12866; however, it is expected to have an annual effect on the economy 
of less than $100 million. Further, this final rule is not likely to 
have a significant adverse effect on supply, distribution, or energy 
use, as further discussed in the RIA. Further, OIRA has not designated 
this final rule as a significant energy action.

K. Privacy Act Statement

    In accordance with 5 U.S.C. 553(c), DOT solicits comments from the 
public to better inform its rulemaking process. DOT posts these 
comments, without edit, including any personal information the 
commenter provides, to www.regulations.gov, as described in the system 
of records notice (DOT/ALL-14 FDMS), which can be reviewed at 
www.dot.gov/privacy.

L. Regulation Identifier Number (RIN)

    A regulation identifier number (RIN) is assigned to each regulatory 
action listed in the Unified Agenda of Federal Regulations. The 
Regulatory Information Service Center publishes the Unified Agenda in 
April and October of each year. The RIN number contained in the heading 
of this document can be used to cross-reference this action with the 
Unified Agenda.

M. Executive Order 13609 and International Trade Analysis

    Executive Order 13609 (``Promoting International Regulatory 
Cooperation'') \91\ requires agencies to consider whether the impacts 
associated with significant variations between domestic and 
international regulatory approaches are unnecessary or may impair the 
ability of American business to export and compete internationally. In 
meeting shared challenges involving health, safety, labor, security, 
environmental, and other issues, international regulatory cooperation 
can identify approaches that are at least as protective as those that 
are or would be adopted in the absence of such cooperation. 
International regulatory cooperation can also reduce, eliminate, or 
prevent unnecessary differences in regulatory requirements.
---------------------------------------------------------------------------

    \91\ 77 FR 26413 (May 4, 2012).
---------------------------------------------------------------------------

    Similarly, the Trade Agreements Act of 1979 (Pub. L. 96-39), as 
amended by the Uruguay Round Agreements Act (Pub. L. 103-465), 
prohibits Federal agencies from establishing any standards or engaging 
in related activities that create unnecessary obstacles to the foreign 
commerce of the United States. For purposes of these requirements, 
Federal agencies may participate in the establishment of international 
standards, so long as the standards have a legitimate domestic 
objective, such as providing for safety, and do not operate to exclude 
imports that meet this objective. The statute also requires 
consideration of international standards and, where appropriate, that 
they be the basis for U.S. standards.
    PHMSA participates in the establishment of international standards 
to protect the safety of the American public. PHMSA has assessed the 
effects of the rulemaking and determined that it will not cause 
unnecessary obstacles to foreign trade.

List of Subjects

49 CFR Part 191

    MAOP exceedance, Pipeline reporting requirements.

49 CFR Part 192

    Incorporation by reference, Integrity assessments, MAOP 
reconfirmation, Material verification, Pipeline safety, Predicted 
failure pressure, Reporting and recordkeeping requirements, Risk 
assessment, Safety devices.

    In consideration of the foregoing, PHMSA amends 49 CFR parts 191 
and 192 as follows:

PART 191--TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE; 
ANNUAL, INCIDENT, AND OTHER REPORTING

0
1. The authority citation for part 191 continues to read as follows:

    Authority: 30 U.S.C. 185(w)(3), 49 U.S.C. 5121, 60101 et seq., 
and 49 CFR 1.97.

0
2. The heading for part 191 is revised to read as set forth above.

0
3. In Sec.  191.1, paragraphs (a) and (b)(2) and (3) are revised, 
paragraph (b)(4) is removed, and paragraph (c) is added to read as 
follows:

[[Page 63295]]

Sec.  191.1   Scope.

    (a) This part prescribes requirements for the reporting of 
incidents, safety-related conditions, annual pipeline summary data, 
National Operator Registry 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). 
This part applies to offshore gathering lines (except as provided in 
paragraph (b) of this section) and to onshore gathering lines, 
including Type R gathering lines as determined in Sec.  192.8 of this 
chapter.
    (b) * * *
    (2) Pipelines on the Outer Continental Shelf (OCS) that are 
producer-operated and cross into State waters without first connecting 
to a transporting operator's facility on the OCS, upstream (generally 
seaward) of the last valve on the last production facility on the OCS. 
Safety equipment protecting PHMSA-regulated pipeline segments is not 
excluded. Producing operators for those pipeline segments upstream of 
the last valve of the last production facility on the OCS may petition 
the Administrator, or designee, for approval to operate under Pipeline 
and Hazardous Materials Safety Administration (PHMSA) regulations 
governing pipeline design, construction, operation, and maintenance 
under 49 CFR 190.9; or
    (3) Pipelines on the Outer Continental Shelf upstream of the point 
at which operating responsibility transfers from a producing operator 
to a transporting operator.
    (c) Sections 191.22(b) and (c) and 191.23 do not apply to the 
onshore gathering of gas--
    (1) Through a pipeline that operates at less than 0 psig (0 kPa);
    (2) Through a pipeline that is not a regulated onshore gathering 
pipeline; or
    (3) Within inlets of the Gulf of Mexico, except for the 
requirements in Sec.  192.612 of this chapter.

0
4. In Sec.  191.3, add definitions for ``Regulated onshore gathering'' 
and ``Reporting-regulated gathering'' in alphabetical order to read as 
follows:

Sec.  191.3  Definitions.

* * * * *
    Regulated onshore gathering means a Type A, Type B, or Type C gas 
gathering pipeline system as determined in Sec.  192.8 of this chapter.
    Reporting-regulated gathering means a Type R gathering line as 
determined in Sec.  192.8 of this chapter. A Type R gathering line is 
subject only to this part.
* * * * *

0
5. In Sec.  191.15, paragraph (a) is revised to read as follows:

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

    (a) Pipeline systems--(1) Transmission or regulated onshore 
gathering. Each operator of a transmission pipeline system or a 
regulated onshore gathering pipeline system must submit Department of 
Transportation (DOT) Form PHMSA F 7100.2 as soon as practicable but not 
more than 30 days after detection of an incident required to be 
reported under Sec.  191.5.
    (2) Reporting-regulated gathering. Each operator of a reporting-
regulated gathering pipeline system must submit DOT Form PHMSA F 
7100.2-2 as soon as practicable but not more than 30 days after 
detection of an incident required to be reported under Sec.  191.5 that 
occurs after May 16, 2022.
* * * * *

0
6. In Sec.  191.17, paragraph (a) is revised to read as follows:

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

    (a) Pipeline systems--(1) Transmission or regulated onshore 
gathering. Each operator of a transmission or a regulated onshore 
gathering pipeline system must submit an annual report for that system 
on DOT Form PHMSA F 7100.2-1. This report must be submitted each year, 
not later than March 15, for the preceding calendar year.
    (2) Type R gathering. Beginning with an initial annual report 
submitted in March 2023 for the 2022 calendar year, each operator of a 
reporting-regulated gas gathering pipeline system must submit an annual 
report for that system on DOT Form PHMSA F 7100.2-3. This report must 
be submitted each year, not later than March 15, for the preceding 
calendar year.
* * * * *

0
7. In Sec.  191.23, revise paragraph (b)(1) to read as follows:

Sec.  191.23  Reporting safety-related conditions.

* * * * *
    (b) * * *
    (1) Exists on a master meter system, a reporting-regulated 
gathering pipeline, or a customer-owned service line;
* * * * *

0
8. In Sec.  191.29, paragraph (c) is added to read as follows:

Sec.  191.29  National Pipeline Mapping System.

* * * * *
    (c) This section does not apply to gathering pipelines.

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

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

    Authority: 30 U.S.C. 185(w)(3), 49 U.S.C. 5103, 60101 et seq., 
and 49 CFR 1.97.

0
10. In Sec.  192.3, add a definition for ``Composite materials'' in 
alphabetical order to read as follows:

Sec.  192.3  Definitions.

* * * * *
    Composite materials means materials used to make pipe or components 
manufactured with a combination of either steel and/or plastic and with 
a reinforcing material to maintain its circumferential or longitudinal 
strength.
* * * * *

0
11. Amend Sec.  192.8 as follows:
0
a. Revise the section heading;
0
b. Add paragraph (a)(5);
0
c. Redesignate paragraph (b) as a paragraph (c);
0
d. Add new paragraph (b); and
0
e. Revise newly redesignated paragraph (c).
    The revisions and addition read as follows:

Sec.  192.8  How are onshore gathering pipelines and regulated onshore 
gathering pipelines determined?

    (a) * * *
    (5) For new, replaced, relocated, or otherwise changed gas 
gathering pipelines installed after May 16, 2022, the endpoint of 
gathering under sections 2.2(a)(1)(E) and 2.2.1.2.6 of API RP 80 
(incorporated by reference, see Sec.  192.7)--also known as 
``incidental gathering''--may not be used if the pipeline terminates 10 
or more miles downstream from the furthermost downstream endpoint as 
defined in paragraphs 2.2(a)(1)(A) through (a)(1)(D) of API RP 80 
(incorporated by reference, see Sec.  192.7) and this section. If an 
``incidental gathering'' pipeline is 10 miles or more in length, the 
entire portion of the pipeline that is designated as an incidental 
gathering line under 2.2(a)(1)(E) and 2.2.1.2.6 of

[[Page 63296]]

API RP 80 shall be classified as a transmission pipeline subject to all 
applicable regulations in this chapter for transmission pipelines.
    (b) Each operator must determine and maintain for the life of the 
pipeline records documenting the methodology by which it calculated the 
beginning and end points of each onshore gathering pipeline it 
operates, as described in the second column of table 1 to paragraph 
(c)(2) of this section, by:
    (1) November 16, 2022, or before the pipeline is placed into 
operation, whichever is later; or
    (2) An alternative deadline approved by the Pipeline and Hazardous 
Materials Safety Administration (PHMSA). The operator must notify PHMSA 
and State or local pipeline safety authorities, as applicable, no later 
than 90 days in advance of the deadline in paragraph (b)(1) of this 
section. The notification must be made in accordance with Sec.  192.18 
and must include the following information:
    (i) Description of the affected facilities and operating 
environment;
    (ii) Justification for an alternative compliance deadline; and
    (iii) Proposed alternative deadline.
    (c) For purposes of part 191 of this chapter and Sec.  192.9, the 
term ``regulated onshore gathering pipeline'' means:
    (1) Each Type A, Type B, or Type C onshore gathering pipeline (or 
segment of onshore gathering pipeline) with a feature described in the 
second column of table 1 to paragraph (c)(2) of this section that lies 
in an area described in the third column; and
    (2) As applicable, additional lengths of pipeline described in the 
fourth column to provide a safety buffer:

                       Table 1 to Paragraph (c)(2)
------------------------------------------------------------------------
                                                            Additional
        Type              Feature            Area         safety buffer
------------------------------------------------------------------------
A..................  --Metallic and    Class 2, 3, or 4  None.
                      the MAOP          location (see
                      produces a hoop   Sec.   192.5).
                      stress of 20
                      percent or more
                      of SMYS.
                     --If the stress
                      level is
                      unknown, an
                      operator must
                      determine the
                      stress level
                      according to
                      the applicable
                      provisions in
                      subpart C of
                      this part.
                     --Non-metallic
                      and the MAOP is
                      more than 125
                      psig (862 kPa).
B..................  --Metallic and    Area 1. Class 3,  If the
                      the MAOP          or 4 location.    gathering
                      produces a hoop  Area 2. An area    pipeline is in
                      stress of less    within a Class    Area 2(b) or
                      than 20 percent   2 location the    2(c), the
                      of SMYS. If the   operator          additional
                      stress level is   determines by     lengths of
                      unknown, an       using any of      line extend
                      operator must     the following     upstream and
                      determine the     three methods:.   downstream
                      stress level     (a) A Class 2      from the area
                      according to      location;.        to a point
                      the applicable   (b) An area        where the line
                      provisions in     extending 150     is at least
                      subpart C of      feet (45.7 m)     150 feet (45.7
                      this part.        on each side of   m) from the
                     --Non-metallic     the centerline    nearest
                      and the MAOP is   of any            dwelling in
                      125 psig (862     continuous 1      the area.
                      kPa) or less.     mile (1.6 km)    However, if a
                                        of pipeline and   cluster of
                                        including more    dwellings in
                                        than 10 but       Area 2(b) or
                                        fewer than 46     2(c) qualifies
                                        dwellings; or.    a pipeline as
                                       (c) An area        Type B, the
                                        extending 150     Type B
                                        feet (45.7 m)     classification
                                        on each side of   ends 150 feet
                                        the centerline    (45.7 m) from
                                        of any            the nearest
                                        continuous 1000   dwelling in
                                        feet (305 m) of   the cluster.
                                        pipeline and
                                        including 5 or
                                        more dwellings.
C..................  Outside diameter  Class 1 location  None.
                      greater than or
                      equal to 8.625
                      inches and any
                      of the
                      following:
                     --Metallic and
                      the MAOP
                      produces a hoop
                      stress of 20
                      percent or more
                      of SMYS;.
                     --If the stress
                      level is
                      unknown,
                      segment is
                      metallic and
                      the MAOP is
                      more than 125
                      psig (862 kPa);
                      or.
                     --Non-metallic
                      and the MAOP is
                      more than 125
                      psig (862 kPa).
R..................  --All other       Class 1 and       None.
                      onshore           Class 2
                      gathering lines.  locations.
------------------------------------------------------------------------

    (3) A Type R gathering line is subject to reporting requirements 
under part 191 of this chapter but is not a regulated onshore gathering 
line under this part.

0
12. Amend Sec.  192.9 as follows:
0
a. Revise the section heading;
0
b. Redesignate paragraph (e) as paragraph (g);
0
c. Add a new paragraph (e) and paragraph (f);
0
d. Revise newly redesignated paragraphs (g)(2) and (3);
0
e. Add paragraphs (g)(4) and (5); and
0
f. Add paragraph (h).
    The revisions and additions read as follows:

Sec.  192.9  What requirements apply to gathering pipelines?

* * * * *
    (e) Type C lines. The requirements for Type C gathering lines are 
as follows.
    (1) An operator of a Type C onshore gathering line with an outside 
diameter greater than or equal to 8.625 inches must comply with the 
following requirements:
    (i) Except as provided in paragraph (h) of this section for pipe 
and components made with composite materials, the design, installation, 
construction, initial inspection, and initial testing of a new, 
replaced, relocated, or otherwise changed Type C gathering line, must 
be done in accordance with the requirements in subparts B though G and 
J of this part applicable to transmission lines. Compliance with 
Sec. Sec.  192.67, 192.127, 192.205, 192.227(c), 192.285(e), and 
192.506 is not required;
    (ii) If the pipeline is metallic, control corrosion according to 
requirements of

[[Page 63297]]

subpart I of this part applicable to transmission lines except for 
Sec.  192.493;
    (iii) Carry out a damage prevention program under Sec.  192.614;
    (iv) Develop and implement procedures for emergency plans in 
accordance with Sec.  192.615;
    (v) Develop and implement a written public awareness program in 
accordance with Sec.  192.616;
    (vi) Install and maintain line markers according to the 
requirements for transmission lines in Sec.  192.707; and
    (vii) Conduct leakage surveys in accordance with the requirements 
for transmission lines in Sec.  192.706 using leak-detection equipment, 
and promptly repair hazardous leaks in accordance with Sec.  
192.703(c).
    (2) An operator of a Type C onshore gathering line with an outside 
diameter greater than 12.75 inches must comply with the requirements in 
paragraph (e)(1) of this section and the following:
    (i) If the pipeline contains plastic pipe, the operator must comply 
with all applicable requirements of this part for plastic pipe or 
components. This does not include pipe and components made of composite 
materials that incorporate plastic in the design; and
    (ii) Establish the MAOP of the pipeline under Sec.  192.619(a) or 
(c) and maintain records used to establish the MAOP for the life of the 
pipeline.
    (f) Exceptions. (1) Compliance with paragraphs (e)(1)(ii), (v), 
(vi), and (vii) and (e)(2)(i) and (ii) of this section is not required 
for pipeline segments that are 16 inches or less in outside diameter if 
one of the following criteria are met:
    (i) Method 1. The segment is not located within a potential impact 
circle containing a building intended for human occupancy or other 
impacted site. The potential impact circle must be calculated as 
specified in Sec.  192.903, except that a factor of 0.73 must be used 
instead of 0.69. The MAOP used in this calculation must be determined 
and documented in accordance with paragraph (e)(2)(ii) of this section.
    (ii) Method 2. The segment is not located within a class location 
unit (see Sec.  192.5) containing a building intended for human 
occupancy or other impacted site.
    (2) Paragraph (e)(1)(i) of this section is not applicable to 
pipeline segments 40 feet or shorter in length that are replaced, 
relocated, or changed on a pipeline existing on or before May 16, 2022.
    (3) For purposes of this section, the term ``building intended for 
human occupancy or other impacted site'' means any of the following:
    (i) Any building that may be occupied by humans, including homes, 
office buildings factories, outside recreation areas, plant facilities, 
etc.;
    (ii) A small, well-defined outside area (such as a playground, 
recreation area, outdoor theater, or other place of public assembly) 
that is occupied by 20 or more persons on at least 5 days a week for 10 
weeks in any 12-month period (the days and weeks need not be 
consecutive); or
    (iii) Any portion of the paved surface, including shoulders, of a 
designated interstate, other freeway, or expressway, as well as any 
other principal arterial roadway with 4 or more lanes.
    (g) * * *
    (2) If a Type A or Type B regulated onshore gathering pipeline 
existing on April 14, 2006, was not previously subject to this part, an 
operator has until the date stated in the second column to comply with 
the applicable requirement for the pipeline listed in the first column, 
unless the Administrator finds a later deadline is justified in a 
particular case:

------------------------------------------------------------------------
                Requirement                      Compliance deadline
------------------------------------------------------------------------
(i) Control corrosion according to          April 15, 2009.
 requirements for transmission lines in
 subpart I of this part.
(ii) Carry out a damage prevention program  October 15, 2007.
 under Sec.   192.614.
(iii) Establish MAOP under Sec.   192.619.  October 15, 2007.
(iv) Install and maintain line markers      April 15, 2008.
 under Sec.   192.707.
(v) Establish a public education program    April 15, 2008.
 under Sec.   192.616.
(vi) Other provisions of this part as       April 15, 2009.
 required by paragraph (c) of this section
 for Type A lines.
------------------------------------------------------------------------

    (3) If, after April 14, 2006, a change in class location or 
increase in dwelling density causes an onshore gathering pipeline to 
become a Type A or Type B regulated onshore gathering line, the 
operator has 1 year for Type B lines and 2 years for Type A lines after 
the pipeline becomes a regulated onshore gathering pipeline to comply 
with this section.
    (4) If a Type C gathering pipeline existing on or before May 16, 
2022, was not previously subject to this part, an operator must comply 
with the applicable requirements of this section, except for paragraph 
(h) of this section, on or before:
    (i) May 16, 2023; or
    (ii) An alternative deadline approved by PHMSA. The operator must 
notify PHMSA and State or local pipeline safety authorities, as 
applicable, no later than 90 days in advance of the deadline in 
paragraph (b)(1) of this section. The notification must be made in 
accordance with Sec.  192.18 and must include a description of the 
affected facilities and operating environment, the proposed alternative 
deadline for each affected requirement, the justification for each 
alternative compliance deadline, and actions the operator will take to 
ensure the safety of affected facilities.
    (5) If, after May 16, 2022, a change in class location, an increase 
in dwelling density, or an increase in MAOP causes a pipeline to become 
a Type C gathering pipeline, or causes a Type C gathering pipeline to 
become subject to additional Type C requirements (see paragraph (f) of 
this section), the operator has 1 year after the pipeline becomes 
subject to the additional requirements to comply with this section.
    (h) Composite materials. Pipe and components made with composite 
materials not otherwise authorized for use under this part may be used 
on Type C gathering pipelines if the following requirements are met:
    (1) Steel and plastic pipe and components must meet the 
installation, construction, initial inspection, and initial testing 
requirements in subparts B though G and J of this part applicable to 
transmission lines.
    (2) Operators must notify PHMSA in accordance with Sec.  192.18 at 
least 90 days prior to installing new or replacement pipe or components 
made of composite materials otherwise not authorized for use under this 
part in a Type C gathering pipeline. The notifications required by this 
section must include a detailed description of the pipeline facilities 
in which pipe or components made of composite materials would be used, 
including:
    (i) The beginning and end points (stationing by footage and mileage 
with latitude and longitude coordinates) of the pipeline segment 
containing composite pipeline material and the counties and States in 
which it is located;
    (ii) A general description of the right-of-way including high 
consequence areas, as defined in Sec.  192.905;

[[Page 63298]]

    (iii) Relevant pipeline design and construction information 
including the year of installation, the specific composite material, 
diameter, wall thickness, and any manufacturing and construction 
specifications for the pipeline;
    (iv) Relevant operating information, including MAOP, leak and 
failure history, and the most recent pressure test (identification of 
the actual pipe tested, minimum and maximum test pressure, duration of 
test, any leaks and any test logs and charts) or assessment results;
    (v) An explanation of the circumstances that the operator believes 
make the use of composite pipeline material appropriate and how the 
design, construction, operations, and maintenance will mitigate safety 
and environmental risks;
    (vi) An explanation of procedures and tests that will be conducted 
periodically over the life of the composite pipeline material to 
document that its strength is being maintained;
    (vii) Operations and maintenance procedures that will be applied to 
the alternative materials. These include procedures that will be used 
to evaluate and remediate anomalies and how the operator will determine 
safe operating pressures for composite pipe when defects are found;
    (viii) An explanation of how the use of composite pipeline material 
would be in the public interest; and
    (ix) A certification signed by a vice president (or equivalent or 
higher officer) of the operator's company that operation of the 
applicant's pipeline using composite pipeline material would be 
consistent with pipeline safety.
    (3) Repairs or replacements using materials authorized under this 
part do not require notification under this section.

0
13. In Sec.  192.13, paragraphs (a) and (b) are revised to read as 
follows:

Sec.  192.13   What general requirements apply to pipelines regulated 
under this part?

    (a) No person may operate a segment of pipeline listed in the first 
column of paragraph (a)(3) of this section that is readied for service 
after the date in the second column, unless:
    (1) The pipeline has been designed, installed, constructed, 
initially inspected, and initially tested in accordance with this part; 
or
    (2) The pipeline qualifies for use under this part according to the 
requirements in Sec.  192.14.
    (3) The compliance deadlines are as follows:

------------------------------------------------------------------------
                 Pipeline                               Date
------------------------------------------------------------------------
(i) Offshore gathering pipeline...........  July 31, 1977.
(ii) Regulated onshore gathering pipeline   March 15, 2007.
 to which this part did not apply until
 April 14, 2006.
(iii) Regulated onshore gathering pipeline  May 16, 2023.
 to which this part did not apply until
 May 16, 2022.
(iv) All other pipelines..................  March 12, 1971.
------------------------------------------------------------------------

    (b) No person may operate a segment of pipeline listed in the first 
column of this paragraph (b) that is replaced, relocated, or otherwise 
changed after the date in the second column of this paragraph (b), 
unless the replacement, relocation or change has been made according to 
the requirements in this part.

------------------------------------------------------------------------
                 Pipeline                               Date
------------------------------------------------------------------------
(1) Offshore gathering pipeline...........  July 31, 1977.
(2) Regulated onshore gathering pipeline    March 15, 2007.
 to which this part did not apply until
 April 14, 2006.
(3) Regulated onshore gathering pipeline    May 16, 2023.
 to which this part did not apply until
 May 16, 2022.
(4) All other pipelines...................  November 12, 1970.
------------------------------------------------------------------------

* * * * *

0
14. In Sec.  192.18, paragraph (c) is revised to read as follows:

Sec.  192.18  How to notify PHMSA.

* * * * *
    (c) Unless otherwise specified, if the notification is made 
pursuant to Sec.  192.8(b)(2), Sec.  192.9(g)(4)(ii) and (h), Sec.  
192.461(g), Sec.  192.506(b), Sec.  192.607(e)(4) and (5), Sec.  
192.619(c)(2), Sec.  192.624(c)(2)(iii) and (c)(6), Sec.  
192.632(b)(3), Sec.  192.710(c)(7), Sec.  192.712(d)(3)(iv) and 
(e)(2)(i)(E), Sec.  192.921(a)(7), Sec.  192.927(b), or Sec.  
192.937(c)(7) to use a different integrity assessment method, 
analytical method, compliance period, sampling approach, pipeline 
material, or technique (i.e., ``other technology'') that differs from 
that prescribed in those sections, the operator must notify PHMSA at 
least 90 days in advance of using the other technology. An operator may 
proceed to use the other technology 91 days after submittal of the 
notification unless it receives a letter from the Associate 
Administrator for Pipeline Safety informing the operator that PHMSA 
objects to the proposed use of other technology or that PHMSA requires 
additional time to conduct its review.

0
15. Amend Sec.  192.150 as follows:
0
a. In paragraph (b)(7)(ii), remove the word ``and'';
0
b. Redesignate paragraph (b)(8) as paragraph (b)(9); and
0
c. Add a new paragraph (b)(8).
    The addition reads as follows:

Sec.  192.150  Passage of internal inspection devices.

* * * * *
    (b) * * *
    (8) Gathering lines; and
* * * * *

0
16. In Sec.  192.452, revise the section heading and paragraph (b) 
introductory text and add paragraphs (c) and (d) to read as follows:

Sec.  192.452  How does this subpart apply to converted pipelines and 
regulated onshore gathering pipelines?

* * * * *
    (b) Type A and B onshore gathering lines. For any Type A or Type B 
regulated onshore gathering line under Sec.  192.9 existing on April 
14, 2006, that was not previously subject to this part, and for any 
onshore gathering line that becomes a regulated onshore gathering line 
under Sec.  192.9 after April 14, 2006, because of a change in class 
location or increase in dwelling density:
* * * * *
    (c) Type C onshore regulated gathering lines. For any Type C 
onshore regulated gathering pipeline under Sec.  192.9 existing on May 
16, 2022, that was not previously subject to this part, and for any 
Type C onshore gas gathering pipeline that becomes subject to this 
subpart after May 16, 2022, because of an increase in MAOP, change in 
class location, or presence of a building intended for human occupancy 
or other impacted site:
    (1) The requirements of this subpart specifically applicable to 
pipelines installed before August 1, 1971, apply to the gathering line 
regardless of the date the pipeline was actually installed; and
    (2) The requirements of this subpart specifically applicable to 
pipelines installed after July 31, 1971, apply only if the pipeline 
substantially meets those requirements.
    (d) Regulated onshore gathering lines generally. Any gathering line 
that is subject to this subpart per Sec.  192.9 at the time of 
construction must meet the requirements of this subpart applicable to 
pipelines installed after July 31, 1971.

[[Page 63299]]

0
17. In Sec.  192.619, revise paragraph (a)(3) and paragraph (c) to read 
as follows:

Sec.  192.619  Maximum allowable operating pressure: Steel or plastic 
pipelines.

    (a) * * *
    (3) The highest actual operating pressure to which the segment was 
subjected during the 5 years preceding the applicable date in the 
second column. This pressure restriction applies unless the segment was 
tested according to the requirements in paragraph (a)(2) of this 
section after the applicable date in the third column or the segment 
was uprated according to the requirements in subpart K of this part:

------------------------------------------------------------------------
        Pipeline segment             Pressure date         Test date
------------------------------------------------------------------------
(i) Onshore regulated gathering   March 15, 2006, or  5 years preceding
 pipeline (Type A or Type B        date pipeline       applicable date
 under Sec.   192.9(d)) that       becomes subject     in second column.
 first became subject to this      to this part,
 part (other than Sec.             whichever is
 192.612) after April 13, 2006.    later.
(ii) Onshore regulated gathering  May 16, 2023, or    5 years preceding
 pipeline (Type C under Sec.       date pipeline       applicable date
 192.9(d)) that first became       becomes subject     in second column.
 subject to this part (other       to this part,
 than Sec.   192.612) on or        whichever is
 after May 16, 2022.               later.
(iii) Onshore transmission        March 15, 2006, or  5 years preceding
 pipeline that was a gathering     date pipeline       applicable date
 pipeline not subject to this      becomes subject     in second column.
 part before March 15, 2006.       to this part,
                                   whichever is
                                   later.
(iv) Offshore gathering           July 1, 1976......  July 1, 1971.
 pipelines.
(v) All other pipelines.........  July 1, 1970......  July 1, 1965.
------------------------------------------------------------------------

* * * * *
    (c) The requirements on pressure restrictions in this section do 
not apply in the following instances:
    (1) An operator may operate a segment of pipeline found to be in 
satisfactory condition, considering its operating and maintenance 
history, at the highest actual operating pressure to which the segment 
was subjected during the 5 years preceding the applicable date in the 
second column of the table in paragraph (a)(3) of this section. An 
operator must still comply with Sec.  192.611.
    (2) For any Type C gas gathering pipeline under Sec.  192.9 
existing on or before May 16, 2022, that was not previously subject to 
this part and the operator cannot determine the actual operating 
pressure of the pipeline for the 5 years preceding May 16, 2023, the 
operator may establish MAOP using other criteria based on a combination 
of operating conditions, other tests, and design with approval from 
PHMSA. The operator must notify PHMSA in accordance with Sec.  192.18. 
The notification must include the following information:
    (i) The proposed MAOP of the pipeline;
    (ii) Description of pipeline segment for which alternate methods 
are used to establish MAOP, including diameter, wall thickness, pipe 
grade, seam type, location, endpoints, other pertinent material 
properties, and age;
    (iii) Pipeline operating data, including operating history and 
maintenance history;
    (iv) Description of methods being used to establish MAOP;
    (v) Technical justification for use of the methods chosen to 
establish MAOP; and
    (vi) Evidence of review and acceptance of the justification by a 
qualified technical subject matter expert.
* * * * *

    Issued in Washington, DC on November 2, 2021, under authority 
delegated in 49 CFR 1.97.
Tristan H. Brown,
Acting Administrator.
[FR Doc. 2021-24240 Filed 11-12-21; 8:45 am]
BILLING CODE 4910-60-P