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

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:

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

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

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

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

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

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 <IP_ADDRESS>.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.

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

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

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

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.

    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<PHONE_NUMBER>.

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.

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:

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 <IP_ADDRESS>.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 <IP_ADDRESS>.6 of

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

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;

    (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