mapping of gravity lines at this time and therefore is finalizing the
rule without this requirement. PHMSA understands commenters' concerns
that gravity line NPMS data submissions could be costly and burdensome.
However, as PHMSA is not requiring these submissions as a part of this
final rule's reporting requirements, the cost and burden of these
submissions were not and should not be considered as a part of the
cost-benefit analysis. If PHMSA determines, following analysis of the
data received on gravity lines, that mapping of these lines or
expanding reporting applicability to lines exempted in this final rule
would be beneficial to improve public safety or protect the
environment, it may consider additional requirements in a future
rulemaking.
    Similarly, PHMSA is not requiring telephonic reporting of accidents
involving gravity lines at this time but may reassess this requirement
in a future rulemaking if analyses of the data suggest that doing so
would enhance prevention, preparedness, and response to hazardous
liquid releases from gravity lines.
    Comments relating to public reporting and the reporting of specific
pipeline attributes discussed issues that PHMSA did not propose in the
NPRM and are therefore out-of-scope and could not be considered for
this rulemaking. Similarly, comments discussing minimum safety
standards be applied to gravity lines were also out-of-scope because
they requested more stringent requirements than what PHMSA proposed in
the NPRM.

B. Reporting Requirements for Gathering Lines

1. PHMSA's Proposal
    In the NPRM, PHMSA also proposed to extend the reporting
requirements of 49 CFR part 195 to all hazardous liquid gathering
lines. Recent data indicates that PHMSA regulates less than 4,000 miles
of the approximately 30,000 to 40,000 miles of onshore hazardous liquid
gathering lines in the United States.\39\ That means that about 90
percent of the onshore gathering line mileage is not currently subject
to any minimum Federal pipeline safety standards. Congress also ordered
the review of existing State and Federal regulations for hazardous
liquid gathering lines in the Pipeline Safety Act of 2011, to prepare a
report on whether any of the existing exceptions for these lines should
be modified or repealed, and to determine whether hazardous liquid
gathering lines located offshore or in the inlets of the Gulf of Mexico
should be subjected to the same safety standards as all other hazardous
liquid gathering lines. Based on the study titled ``Review of Existing
Federal and State Regulations for Gas and Hazardous Liquid Gathering
Lines'' \40\ that was performed by the Oak Ridge National Laboratory
and published on May 8, 2015, PHMSA proposed additional regulations to
help ensure the safety of hazardous liquid gathering lines.
---------------------------------------------------------------------------

    \39\ GAO-12-388: ``Pipeline Safety: Collecting Data and Sharing
Information on Federally Unregulated Gathering Pipelines Could Help
Enhance Safety,'' March 2012, pg. 7; http://www.gao.gov/assets/590/589514.pdf.
    \40\ http://www.phmsa.dot.gov/staticfiles/PHMSA/DownloadableFiles/Files/report_to_congress_on_gathering_lines.pdf.
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    For PHMSA to effectively analyze safety performance and risk of
gathering lines, we need basic data about those pipelines. PHMSA has
statutory authority to gather data for all gathering lines (49 U.S.C.
60117(b)). Accordingly, PHMSA proposed to add Sec.  195.1(a)(5) to
require that the operators of all gathering lines (whether onshore,
offshore, regulated, or unregulated) comply with requirements for
submitting annual, safety-related condition, and incident reports.
2. Summary of Public Comment
    PHMSA received comments on hazardous liquid gathering lines that
echoed those for gravity lines. Citizen groups and individuals again
requested that the requirements for these lines include GIS mapping and
minimum safety standards; that the reporting include location,
operation, condition, and history; and that inspection reports, notices
of violation, and similar documents be made available to the public.
Trade organizations again commented on compliance costs and recommended
that the reporting requirement be limited to annual and incident
reports with an abbreviated form, have a phase-in implementation over 1
year, and exempt lower-risk pipelines. Specifically, API noted again
that, as rural gathering lines are not subject to operator
qualification, control room management, leak detection, and HCA
requirements, those areas should be excluded from reporting.
    Trade organizations also made several additional recommendations
related to the scope of applicability, the scope of requirements, and
implementation. The Independent Petroleum Association of America (IPAA)
commented that PHMSA exceeds its authority in requiring operators of
gathering lines to submit annual, safety-related condition, and
incident reports. The GPA and other organizations noted that PHMSA did
not fully account for the burden increase and cost of the reporting
requirements for gathering lines in the preliminary RIA. The GPA
recommended that information requested under Sec.  195.61 and Sec.
195.64 be excluded from data collection. Numerous trade organizations
identified accident reporting for these lines as costly and
duplicative. The Louisiana Mid-Continent Oil and Gas Association
(LMOGA) commented that most, if not all accident information requested
for gathering lines is already required to be reported under other
existing Federal and State regulations, and the GPA recommended that
information collected through an abbreviated Annual Report could be
paired with Accident Reporting on Form F 7000-1 (rev 7-2014). LMOGA
also recommended that mapping of gathering lines not be required
because of incidental environmental impacts on wetlands, permitting,
and resource costs for teams to enter wetlands and track these lines.
    The Offshore Operators Committee (OOC) requested that PHMSA make
clear in the final rule that the agency's intent is not to have the
proposed reporting requirements apply to gathering lines offshore
within State waters that are currently not regulated by PHMSA or the
Bureau of Safety and Environmental Enforcement (BSEE) or to other
gathering lines that are regulated by BSEE.
    Finally, commenters asked for implementation periods that ranged
from 1 year (API-AOPL) to 10 years (Enterprise Products Partners) after
the effective date of the rule.
    During the meeting on February 1, 2016, the LPAC recommended that
PHMSA modify the NPRM to (1) require reporting from gathering pipeline
operators using streamlined forms and (2) set a 1-year implementation
period for the annual reporting requirement and a 6-month
implementation period for the accident reporting requirement.
3. PHMSA Response
    PHMSA appreciates the information provided by the commenters
regarding the scope and timing of the requirements for gathering lines.
Regarding the comment that the proposed reporting requirement of Sec.
195.1(a)(5) exceeds PHMSA's statutory authority, PHMSA notes that the
Federal Pipeline Safety Statutes state, in relevant part, ``[t]he
Secretary may require owners and operators of gathering lines to
provide the Secretary

information pertinent to the Secretary's ability to make a
determination as to whether and to what extent to regulate gathering
lines.'' 49 U.S.C. 60117(b). PHMSA has determined that, in order to
decide whether and to what extent to regulate gathering lines, as
permitted by Congress, PHMSA requires pertinent information about those
pipelines, including elements of the data contained in annual, safety-
related condition, and incident reports. With this reporting
requirement, PHMSA is not encroaching on the States' regulatory
authority, nor creating new jurisdiction. Rather, PHMSA is collecting
pertinent information to determine if future regulation is necessary
for the statutory purpose of promoting pipeline safety.
    More specifically, PHMSA is collecting items in the annual report
that primarily include the mileage count for those gathering lines
currently unregulated, the diameters of those lines, and whether they
are operating at greater or less than 20 percent SMYS. The goal of
collecting this specific information is to provide PHMSA with a better
understanding of the scope of the Nation's gathering pipeline
infrastructure. As previously stated, recent data indicates PHMSA
regulates only approximately 4,000 miles of the estimated 30,000 to
40,000 miles of onshore hazardous liquid gathering lines in the United
States. That means that as much as 90 percent of the onshore gathering
line mileage is not currently subject to any minimum Federal pipeline
safety standards, and little is known about that mileage.
    In requiring accident reports for otherwise unregulated gathering
lines, PHMSA is collecting data that includes the underlying cause for
the accident, where the accident was located and how it was reported to
the operator, and a value for any property damage caused. This data
will be essential to understanding and managing risk. PHMSA uses
information reported by pipeline operators to identify trends, provide
performance measures, and understand the causes and consequences of
pipeline incidents. Reporting requirements are in place for all
pipelines except for the gravity and gathering pipelines addressed by
this final rule. Each year, the U.S. Coast Guard's National Response
Center receives several notifications of hazardous liquid releases
involving ``gathering lines,'' but details on these releases are not
sufficient to understand the factors that contributed to the releases
and the damages, or to evaluate whether the lines involved are
gathering lines over which PHMSA has jurisdiction.\41\ The reporting
requirements for gathering lines will help PHMSA have a more complete
understanding of the risks these lines may pose.
---------------------------------------------------------------------------

    \41\ NRC data for 2010 through 2014 show 116 incidents
categorized as ``pipeline'' incidents and that specifically include
the term ``gathering'' in the incident description. Many more
pipeline incidents could also be from gathering lines.
---------------------------------------------------------------------------

    PHMSA notes that one of its challenges is to understand and target
risk, which requires a systematic approach to risk management,
including a ``comprehensive understanding of the factors contributing
to risk and the ability to focus resources in those areas that pose the
greatest risk.'' One of PHMSA's strategies for dealing with this
challenge is to improve data collection and analysis, collect the right
data to evaluate risks from unregulated entities, and improve the
transparency of information and public awareness of pipeline and
hazardous materials safety issues. The long-term benefits of having
better information may include reducing incidents, enhancing incident
response, and increasing public confidence.
    As such, PHMSA is finalizing the requirement for operators of
gathering lines to report information annually, starting 1 year from
the rule's effective date, and to report accidents and safety-related
conditions starting 6 months from the final rule's effective date.
PHMSA considers these deadlines practicable in view of the scope of the
information requested. To facilitate reporting and address commenters'
concerns about providing clear instructions on data elements that must
be filled out for gathering lines, PHMSA has modified its existing
reporting form to provide clear instructions, including skip patterns,
on the relevant sections that gathering line operators must fill out.
In response to API's specific suggestions regarding operator
qualification, control room management, leak detection, and HCA
reporting, these revisions exempted rural gathering lines from any
fields that involve ``Could Affect HCA'' data. PHMSA recognizes that
operators who are not currently submitting data will have to register
for an identifier, but PHMSA expects the burden on operators to do this
is small. In its analysis, PHMSA assumed that a majority of the
reporting of currently unregulated gathering lines would be done by
operators who already have OPIDs. PHMSA estimates that, at a minimum,
approximately 20 operators will need to submit information for
gathering lines for the first time, and another 56 operators will add
information about gathering lines to their existing annual reports.
PHMSA estimates the total reporting burden at 402 hours per year, on
average. See the revised RIA accompanying the final rule for additional
detail.
    Some commenters requested that PHMSA clarify whether these
reporting requirements applied to offshore gathering lines in State
waters. As the purpose of the information collection is to evaluate the
public risk posed by gathering lines, PHMSA found it appropriate to
extend the reporting requirements to certain offshore gathering lines
in State waters.
    In its proposal, PHMSA did not intend to require mapping or NPMS
submissions for gathering lines. Under 49 U.S.C. 60132, only
transmission line operators are required to submit mapping data for use
in the NPMS; PHMSA does not have the explicit authority to collect NPMS
data for gathering lines. PHMSA is therefore finalizing the rule
without imposing this requirement on operators of gathering lines.
    Similar to requirements for gravity lines, PHMSA is not requiring
telephonic reporting of accidents involving gathering lines to PHMSA at
this time since such a requirement would not support the purpose of
this data collection effort, which is to enable PHMSA to evaluate risk
over time for potential future action. PHMSA notes that operators must
still report spills to the National Response Center and other relevant
authorities. PHMSA will reassess the utility of requiring notification
for incidents involving gathering lines in a future rulemaking if the
analyses suggest that such notifications would enhance prevention,
preparedness, and response to hazardous liquid releases from gathering
lines.
    Certain commenters also stated their belief that PHMSA neglected to
account for the costs and burden associated with the initial compiling
of the data needed to complete the forms. In many cases, the commenters
suggested, information may not have been recorded or may not have been
provided during mergers or acquisitions. PHMSA noted in the RIA that it
expects operators to have the requested information readily available,
as it is essential for pipeline operation and safety. PHMSA allows
operators to enter ``unknown'' when values cannot be determined for
certain data fields. In the burden estimate, PHMSA allotted time for
operators to compile the proper data and organize it into the requested
format. See the RIA for further details. PHMSA did not impose minimum
safety standards on currently unregulated gathering lines, as some

commenters suggested, because the agency currently does not have data
to analyze what risk, if any, those lines may pose to surrounding
communities and environments. However, under these provisions, PHMSA
will gather data on unregulated gathering lines and will use that data
to determine whether additional safety regulations may be necessary.

C. Pipelines Affected by Extreme Weather and Natural Disasters

1. PHMSA's Proposal
    Recent events demonstrate the importance of ensuring that our
Nation's waterways are adequately protected in the event of a natural
disaster or extreme weather. PHMSA is aware that responsible operators
might do such inspections; however, because it is not a requirement,
some operators do not. Therefore, PHMSA proposed to require that
operators perform an additional inspection within 72 hours after the
cessation of an extreme weather event such as a hurricane or flood, an
earthquake, a natural disaster, or other similar event.
    Specifically, PHMSA proposed that an operator must inspect all
potentially affected pipeline facilities after an extreme weather event
to help ensure that no conditions exist that could adversely affect the
safe operation of that pipeline. The operator would be required to
consider the nature of the event and the physical characteristics,
operating conditions, location, and prior history of the affected
pipeline in determining the appropriate method for performing the
inspection required. The initial inspection must occur within 72 hours
after the cessation of the event, defined as the point in time when the
affected area can be safely accessed by available personnel and
equipment required to perform the inspection. Based on PHMSA's
experience and coordination with operators following natural disasters,
PHMSA has found that 72 hours is reasonable and achievable in most
cases. If an operator finds an adverse condition, the operator must
take appropriate remedial action to best ensure the safe operation of a
pipeline based on the information obtained as a result of performing
the inspection. PHMSA specifically asked for comments on how operators
currently respond to these events, what type of events are encountered,
and if a 72-hour response time is reasonable.
2. Summary of Public Comment
    Some trade organizations recommended that certain requirements be
eliminated altogether or consolidated to reduce what they considered to
be duplicative of existing emergency planning requirements in Sec.
195.402(e)(4).
    Commenters were nearly unanimous in requesting that PHMSA clarify
the definition of extreme weather event, the 72-hour timeline, and the
timeline for mitigating or repairing anomalies. The GPA recommended
that PHMSA either define exactly which events require response and
inspection or establish performance expectations without partially
defining the criteria, while the County of Santa Barbara recommended
that the proposed regulations specify a threshold at which action would
be required. Congresswoman Lois Capps (California) recommended that
PHMSA include definitions and/or citations of existing definitions for
qualifying events and the responsible party for such a determination.
Congresswoman Capps also recommended that PHMSA clarify the terminology
for an ``appropriate method for performing the inspection'' after the
event.
    In addition to clarification of the definition of extreme weather
event, trade groups also requested clarification of the 72-hour
timeline following an extreme weather event, including how they would
determine the cessation of the event, what appropriate action they
would need to take following an event, and how to address the
possibility of continued danger facing personnel or issues with
availability of personnel and resources following an event.
    API-AOPL recommended that PHMSA define cessation as the point in
time when no further threats to personnel safety or equipment exist in
the affected area, allowing for safe access by pipeline personnel and
equipment. They also recommended that the 72-hour window commence only
once personnel and equipment could safely access the affected area.
    Citizen groups and individuals requested that operators be required
to proactively address known risks and vulnerabilities in advance of an
extreme weather event. For example, one organization recommended
additional requirements to identify areas that are particularly
vulnerable to extreme weather events or natural disasters, (e.g.,
stream crossings, and to develop proactive preventive measures.) The
Alaska Wilderness League et al. recommended mandatory prevention
measures that include shutting down pipeline operations in case of an
imminent flood to prevent spills such as the 2011 Exxon Mobil
Yellowstone River spill. Citizen groups also requested immediate
reporting to PHMSA when remedial action is required and that this
information be made publicly available. The Environmental Defense
Center requested that PHMSA provide specific, enforceable requirements
for shutdown or other remedial action should an inspection reveal
damage or anomalies, and that PHMSA clarify the type of events covered
and the inspection methodology required.
    Finally, the OOC recommended that PHMSA coordinate with BSEE and
the U.S. Coast Guard for activities that occur after hurricanes.
    During the meeting on February 1, 2016, the LPAC recommended that
PHMSA modify the NPRM to (1) include landslides as an extreme weather
event, (2) clarify that other similar events are those likely to damage
infrastructure, and (3) require operators to inspect all potentially
affected pipeline facilities to detect conditions that could adversely
affect the safe operation of the pipeline. The LPAC also recommended
that PHMSA modify the language regarding the inspection method to
require operators to consider the nature of the event and the physical
characteristics, operating conditions, location, and prior history of
the affected pipeline in determining the appropriate method for
performing the initial inspection to determine damage and the need for
additional assessments. Finally, the LPAC recommended that PHMSA
clarify that the inspection must commence within 72 hours after the
cessation of the event, which is defined as the point in time when the
affected area can be safely accessed by the personnel and equipment,
accounting for personnel and equipment availability.
3. PHMSA Response
    PHMSA disagrees with the comments stating the provisions at Sec.
195.414 are unnecessary and duplicate operation and maintenance (O&M)
manual requirements already contained in the response plan requirements
under Sec.  195.402. While Sec.  195.402 does require that operators
include certain ongoing monitoring measures in their O&M manuals, the
proposed Sec.  195.414 is much more specific in requiring that
operators take appropriate remedial action to best ensure the safe
operation of a pipeline based on the information obtained as a result
of performing the post-event inspection required under paragraph (a) of
this section. This will ensure that operators take the prescribed
actions; having measures described in an operator's O&M manual, as
previously required, is not equivalent to action. PHMSA maintains that
separate and more specific requirements are

warranted to best ensure public safety and environmental protection
following extreme events. Additionally, PHMSA notes that reporting is
coordinated with BSEE, the U.S. Coast Guard, and other agencies under
existing notification procedures if the assessment determines there was
a release involving their areas of responsibility. Both 49 CFR parts
194 and 195 require operators to report spills to the National Response
Center.
    PHMSA appreciates the feedback provided by the commenters regarding
the need for greater clarity in the definition of extreme events and
natural disasters and expectations on the timing and scope of post-
event inspections. In developing the requirements, PHMSA sought to
balance being explicit regarding the types of events that could
increase the risk of a release and therefore require inspections, with
providing sufficient flexibility to account for diverse geographical
and pipeline design factors. PHMSA recognizes that the language
recommended by the LPAC is useful in striking this balance and adopted
most its revisions in the final rule under Sec. Sec.  195.414(a), (b),
and (c). PHMSA is removing the language ``other similar event'' as
PHMSA found the phrase to be vague and unnecessary to accomplish the
goals of the provision but is maintaining the LPAC's recommended
language regarding the ``likelihood to damage infrastructure.'' Per the
finalized requirement, operators must inspect all potentially affected
pipeline facilities following extreme weather events or natural
disasters with the likelihood of damaging infrastructure, such as named
hurricanes or tropical storms; floods that exceed the high-water banks
of rivers, shorelines or creeks; and landslides or earthquakes
occurring within the area of a pipeline, in order to detect conditions
that could adversely affect the safe operation of that pipeline. As
discussed earlier in this document, the conditions that trigger this
requirement are those that have the potential to cause river scour,
soil subsidence, or earth movement, all of which can subject a pipeline
to additional external loads and forces and cause the pipeline to fail.
Pipeline operators are already required to understand and analyze the
impact such weather events and natural disasters may have on their
systems based the physical characteristics, operating conditions,
location, and prior history of susceptible pipelines.
    PHMSA retained the remedial actions unchanged from the proposal.
While PHMSA intends for operators to inspect pipelines as soon as
possible after an event ends, PHMSA also agrees with commenters that
personnel safety is paramount. Accordingly, PHMSA clarified that the
cessation of the event occurs as soon as it is safe for personnel and
equipment to access the area. Operators are responsible for determining
when each site is safe enough for entry.
    In response to commenters who sought greater flexibility in the
timing of the inspections by leaving it up to the operators, PHMSA
disagrees and maintains that setting clear and consistent timelines is
essential to ensuring that all operators detect and address any issues
promptly. The final rule does provide a fallback to operators who must
delay the start of actions beyond this time due to availability of
equipment, but these operators must notify the Regional Director. This
addition to the LPAC-approved language allows operators to retain
flexibility due to unavailable equipment, while ensuring accountability
and prompt action. PHMSA considers 72 hours to be a reasonable period
for mobilizing personnel and equipment following an event.
    In response to commenters who expressed concerns that inspections
cannot be reasonably be completed within the 72-hour window, PHMSA
notes that the proposal did not require completion of the inspections
within 72 hours, and neither does the final rule; PHMSA recognizes that
this needed to be clarified in the rule text and has done so in the
final rule. The final rule accordingly describes the actions it expects
operators to perform, starting within 72 hours after the cessation of
the event. Recognizing that some actions will need to be site-specific,
PHMSA provides flexibility to operators to determine the measures that
are appropriate to the event, pipeline design, and circumstances.
    PHMSA is receptive to the recommendation that operators should take
precautionary measures to minimize exposure in advance of and during an
extreme event (e.g., reducing operating pressure or shutting down a
pipeline), and notes that the current IM regulations require operators
to know and understand risks to their system, which includes the threat
of extreme events such as flooding or wind damage. To execute their IM
programs and assessments on non-HCA lines as per this final rule,
operators will need to have pipeline system information to address
risks to their systems. Operators will use the information they have
gathered on their entire pipeline system to monitor conditions and
determine any anticipated risks to their pipelines, including extreme
weather events. Given that the existing IM regulations require
preventive and mitigative measures for HCAs, which often include river
crossings, it is appropriate for this section to address post-natural
disaster inspections for damage specifically.

D. Periodic Assessment of Pipelines Not Subject to IM

1. PHMSA's Proposal
    PHMSA proposed to require integrity assessments for pipeline
segments in non-HCAs. PHMSA believes that expanded assessment of non-
HCA pipeline segments areas will provide operators with valuable
information they may not have collected if regulations were not in
place; such a requirement would help ensure prompt detection and
remediation of corrosion and other deformation anomalies in all
locations, not just HCAs. Specifically, the proposed Sec.  195.416
would require operators to assess non-HCA (non-IM) pipeline segments
with an ILI tool at least once every 10 years, which allows operators
to prioritize HCA assessments. PHMSA proposed to allow other assessment
methods if an operator provides OPS with prior written notice that a
pipeline is not capable of accommodating an ILI tool. Such alternative
technologies would include hydrostatic pressure testing or appropriate
forms of direct assessment.
    Although imposing the full set of IM requirements in Sec.  195.452
on non-HCA pipeline segments was not proposed, operators would be
required to comply with the other provisions in 49 CFR part 195 in
implementing the requirements in Sec.  195.416. That includes having
appropriate provisions for performing periodic assessments and any
resulting repairs in an operator's procedural manual (see Sec.
195.402); adhering to the recordkeeping provisions for inspections,
tests, and repairs (see Sec.  195.404); and taking appropriate remedial
action under proposed Sec.  195.422, which, based on the existing IM
repair criteria at Sec.  195.452(h), identified specific types of
anomalies and the timeframes by which they must be remediated.
Operators would also follow the requirements for ``discovery of
condition,'' where the discovery of a condition occurs when an operator
has adequate information to determine that a condition exists. The
operator must promptly, but no later than 180 days after an assessment,
obtain sufficient information about a condition to determine whether
the condition could adversely affect the safe operation of the
pipeline, unless 180 days is impracticable as determined by

PHMSA. PHMSA sought public comment on the alternatives it considered
under this specific proposal and on quantifying these alternatives in
the regulatory impact analysis.
2. Summary of Public Comment
    Trade organizations offered comments and language revisions on the
methods and requirements included in the periodic assessments,
implementation period, inspection intervals, and exemptions for lower
risk pipelines. Enterprise Products Partners requested that operators
be afforded the latitude they have under current IM regulations to
determine the actual threats to pipeline integrity present on a given
segment and to tailor their integrity assessment program accordingly.
For instance, Enterprise suggested that PHMSA revise the proposal to
clarify that a crack tool is not required for every ILI assessment,
stating specifically that ``an additional ILI crack tool is beneficial
only when there is an identified threat to the pipeline segment that
could result in cracks, such as cyclic fatigue. Yet PHMSA proposes to
require a [crack tool] in all circumstances and on every pipeline
segment.'' Other trade organizations echoed this and requested that
PHMSA incorporate alternatives to ILI tools for periodic assessments
into the rule. Trade organizations also recommended that PHMSA ensure
the rule is consistent with existing IM rules, including the
reassessment intervals and implementation period. The Texas Pipeline
Association requested that reassessment intervals be based on sound
engineering judgement and industry consensus standards. Finally, trade
organizations recommend that PHMSA limit and specify the type of
pipelines to which the requirement would apply, with some commenters
requesting specific exemptions for short lines and CO2
pipelines. API-AOPL requested that PHMSA clarify that operators would
not need to run assessments on idle or out-of-service pipelines. API-
AOPL also requested that PHMSA clarify that it intends for the
requirements to include transmission lines only. Finally, the GPA
requested that PHMSA rely on American Society of Nondestructive Testing
(ASNT) ILI PQ as the standard for data analysis rather than the current
language ``qualified by knowledge, training, and experience.'' The GPA
submitted additional comments to PHMSA on March 24, 2016, expressing
concerns that PHMSA misrepresented aspects of this proposal during the
LPAC meeting. In the LPAC meeting the GPA claimed that PHMSA asserted
that currently regulated gathering lines are subject to assessments;
the GPA believes that this statement was inaccurate and led to a vote
by the committee that was not based on accurate facts. Further, the GPA
suggested that ``it is possible there are gathering lines in non-rural
areas which do not meet the Census Bureau definitions for high or other
population areas. Thus, when properly applying the regulations as
currently written, there are gathering lines, which are regulated by
PHMSA and its state partners for safety purposes that are not subject
to periodic assessments.''
    Trade organizations also commented on the cost of expanding
requirements for pipelines located outside of HCAs. The Texas Pipeline
Association commented that raising the level of regulation on
facilities outside of HCAs will redirect resources from high-risk areas
to lower-risk areas. They requested that PHMSA consider the costs to
operators of the proposed changes related to facilities outside of
HCAs. The OOC also commented that offshore lines present unique
challenges that make them ill-fitted for ILI technology and hydrotests.
    Other groups and individuals commented on the methods and
requirements included in the periodic assessments, inspection
intervals, and additional requirements. A 5-year inspection interval
was generally favored by citizen groups and individuals, including the
Alliance for Great Lakes Et al. Congresswoman Capps highlighted that a
3-year interval between inspections had proven to be inadequate to
detect corrosion that caused the Plains All American oil pipeline
rupture in May 2015. These commenters also requested clarification that
alternative methods of assessment must account for inspection along the
entire pipeline both inside and outside HCAs and expressed concern with
waivers for ILI tools or the use of direct assessment.
    The NTSB requested that PHMSA harmonize the gas and liquid
regulations to the maximum extent practicable and cautioned that direct
assessment is an ineffective alternative technology for IM when
applying the 10-year assessment requirement for the integrity of an
entire pipeline. They recommended that the IM program encompass a broad
range of available IM technologies including, but not limited to, ILI,
magnetic flux leakage, ultrasonic testing, and tests directed at
determining the integrity of the pipe coating.
    Finally, some citizen groups and individuals requested that
inspection reports be made publicly available and that operators be
required to submit primary inspection results and data to PHMSA. The
Environmental Defense Center recommended third-party verification of
inspection reports based on corrosion underreporting. These groups also
requested risk assessment on non-IM pipelines and annual inspections
for all federally regulated hazardous liquid pipelines.
    During the February 1, 2016, meeting, the LPAC recommended PHMSA
modify the NPRM to clarify its application to pipelines regulated under
Sec.  195.1 that are not subject to the IM requirements in Sec.
195.452. The LPAC also made additional language recommendations to
clarify the method of the assessment when ILI tools are impracticable,
including pressure tests, external corrosion direct assessment, or
other technology that the operator demonstrates can provide an
equivalent understanding of the condition of the line pipe.
3. PHMSA Response
    PHMSA appreciates the information provided by the commenters. PHMSA
notes that the LPAC, with minor tweaks, found the provision for
requiring operators to perform these periodic assessments on all
covered pipelines not subject to the integrity management requirements
under Sec.  195.452 to be a cost-effective, practicable, and
technically feasible provision.
    However, several commenters noted challenges and cost-benefit
concerns with assessing offshore lines and regulated rural gathering
lines as a part of this proposal. In this final rule, PHMSA is limiting
the assessment requirement to onshore, non-HCA, non-gathering lines
that can accommodate inline inspection tools.
    Under the current regulations, PHMSA notes that approximately 45
percent of hazardous liquid pipelines are required to be assessed per
the IM requirements by being located within an HCA or because they can
affect an HCA. PHMSA has determined that, through this provision, most
onshore non-HCA mileage will be assessed at a consistent rate. Further,
as pipeline operators continue to replace pipe through modernization
projects and repairs, PHMSA assumes that virtually all the Nation's
pipeline mileage will be piggable within the next few decades.
    In the NPRM, PHMSA did not intend for the requirements applicable
to lines outside of HCAs to be more stringent than those applicable to
lines in HCAs. PHMSA agreed with the commenters and the LPAC that it is
appropriate to provide the same flexibility for the assessment of lines
outside of HCAs as

lines within HCAs, but PHMSA notes that many of these concerns appeared
to be in response to PHMSA's requirement to assess all non-HCA lines,
even ones that were not readily piggable. As discussed above, this
final rule's non-HCA assessment requirement now applies to piggable,
onshore transmission line only. This final rule does allow operators to
use pressure testing, direct assessment, or other technology in cases
when in-line inspections are impracticable. PHMSA has determined that
ILI tools may not be available for all pipe diameters and threats being
assessed, and providing operators the ability to use these other
assessment methods on piggable lines is appropriate at this time.
    Further, per the comments received from commenters, including API
and Enterprise, related to the use of crack tools, PHMSA has revised
the final rule, at both Sec. Sec.  195.416 and 195.452, to require
crack tools only when there is an identified or probable risk or threat
supporting their use. For example, if operators have identified a
pipeline segment with identified or probable risks or threats related
to corrosion and deformation anomalies, including dents, gouges, or
grooves, then the operator must assess that segment with a tool capable
of detecting those anomalies. Similarly, operators should assess
pipeline segments with an identified or probable risk or threat related
to cracks using a tool capable of detecting crack anomalies.
Essentially, operators should always be selecting an appropriate
assessment tool based on the pertinent threats to a given pipeline
segment that have been identified by an operator's risk assessment. An
operator's risk assessment should always be driving its integrity
assessments and the integrity management program. An operator cannot
properly maintain its pipeline if it does not know what threats to
which the pipeline is susceptible to and which tools the company should
be selecting to assess those threats. These threats can include, but
are not limited to, pipe that may have manufacturing defects or have
otherwise experienced in-service incidents.
    Under the existing requirements of Sec.  195.452(c)(1) (after which
PHMSA modeled the new assessment requirements in Sec.  195.416),
operators must select an assessment method capable of assessing seam
integrity and of detecting corrosion and deformation anomalies if the
applicable pipe is low-frequency ERW pipe or lap-welded pipe
susceptible to longitudinal seam failure. PHMSA has interpreted and
intended the phrase ``susceptible to seam failure'' to apply to both
low-frequency ERW pipe and lap-welded pipe. In this final rule, PHMSA
has expanded the assessment provisions to require operators to use a
tool or tools capable of assessing seam integrity, cracking, and of
detecting corrosion and deformation anomalies on low-frequency ERW
pipe, pipe with a seam factor less than 1.0 (as defined in Sec.
195.106(e)) \42\)), or lap-welded pipe susceptible to longitudinal seam
failure. Certain stakeholders may interpret this requirement to mean
that these tools will need to be run on every segment of low-frequency
ERW pipe, pipe with a seam factor of less than 1.0, or lap-welded pipe.
However, PHMSA only explicitly requires the use of these tools for
segments of low-frequency ERW pipe, pipe with a seam factor less than
1.0, or lap-welded pipe when these types of pipe are determined by an
operator to be susceptible to longitudinal seam failure based on
excavation findings, examinations, leaks, failures, pressure tests,
inline inspections, other operating history, and the manufacturing
history of the pipe vintage and its history of seam leaks and failures.
---------------------------------------------------------------------------

    \42\ 49 CFR 195.106(e) has seam factors for pipe seams that need
to be de-rated for maximum operating pressure determination. A de-
rated seam factor would be below 1.0 and include furnace lap welded
and furnace butt welded pipe seams.
---------------------------------------------------------------------------

    Similarly, PHMSA found that the proposed requirements for
``discovery of condition'' under Sec.  195.416 were more stringent than
the revisions proposed for Sec.  195.452. To be consistent with the
revised requirements under Sec.  195.452 regarding the discovery of
condition, the operator has 180 days to obtain sufficient information
on conditions and make the required determinations, unless the operator
can demonstrate that the 180-day timeframe is impracticable. In cases
where an operator does not have adequate information within 180 days
following an assessment, pipeline operators must notify PHMSA and
provide an expected date when that information will become available.
These revisions will provide consistency for the discovery of condition
across all regulated HCA and non-HCA lines.
    PHMSA also agreed with the commenters and the LPAC that it is
necessary to clarify which pipelines fall under the non-HCA assessment
requirements. However, upon further review, PHMSA found that adopting
the LPAC-recommended language for Sec.  195.416(a), by clarifying
application of this requirement to pipelines regulated under Sec.
195.1 that are not subject to the IM requirements in Sec.  195.452,
would extend this requirement beyond PHMSA's or the LPAC's intent and
would cover facilities not previously intended, such as pump stations.
Therefore, instead of strictly adopting the language proposed by the
LPAC, PHMSA is instead specifying that these requirements apply to
onshore, piggable line pipe not covered under the IM requirements,
including the relevant line pipe within pump stations, but not other
appurtenances and components like metering stations, tanks, etc.
Further, PHMSA is not requiring IM 5-year assessments but is requiring
operators to continue the implementation of the preventive and
mitigative measures under IM (Sec.  195.452(i)) for appurtenances,
pumps, tanks, etc., for these facilities that could affect a HCA. PHMSA
believes this clarification captures the intent of the LPAC members.
    In response to the GPA's suggestion for an alternative standard for
data analysis, PHMSA's existing process for data analysis has been
through a rigorous rulemaking process. PHMSA is not incorporating
alternative standards into this rule making that were not included at
an earlier rulemaking stage and were not subject to public comment.
    Regarding the GPA's other concern as to whether PHMSA provided the
LPAC with inaccurate information concerning the extent to which
operators are already required to perform assessments on gathering
lines versus the new assessment requirements PHMSA was proposing in the
NPRM, PHMSA notes that on pages 180 and 181 of the LPAC meeting
transcript PHMSA clearly states that it is proposing subjecting
currently regulated rural gathering lines to periodic assessment and
repair requirements in Sec. Sec.  195.416 and 195.422, saying, ``When
it comes to the gathering lines that we don't currently regulate,
[that] the regulations don't currently address, the only requirements
we're applying will be the reporting requirements that we discussed
prior. In the [NPRM], when it came to regulated rural gathering lines,
we proposed to subject them to the assessment requirements in [Sec.
195.]416 and [Sec.  195.]422. There's actually a proposal in the NPRM
to link the two sections together, but it would not require that lines
that are currently, today, not regulated to be assessed.'' The
statement by PHMSA at the LPAC meeting that the GPA questions states
that regulated rural gathering lines have an assessment requirement in
the NPRM as opposed to currently unregulated gathering lines, which do
not. Further discussion and voting at the LPAC meeting indicated that
the committee members fully

understood PHMSA's proposal, with committee members clarifying the
definition by asking it to be revised to ``transmission and regulated
gathering lines'' and noting ``there's clarity with this [definition]
now.''
    Regarding the GPA's other comment on the possibility of the
existence of gathering lines in non-rural areas that are not assessed,
PHMSA notes this is incorrect. Currently, the only regulated gathering
lines that are not subject to assessment requirements are regulated
rural gathering lines, which, per their name, are in rural areas. Under
existing Sec.  195.1(a)(4), any onshore gathering lines located in non-
rural areas and gathering lines located in Gulf of Mexico inlets are
covered by 49 CFR part 195, and if these gathering lines are within
HCAs or could affect HCAs, they are subject to the full IM program
requirements, including integrity assessments, under the current Sec.
195.452. As defined in Sec.  195.2, a ``rural area'' means ``outside
the limits of any incorporated or unincorporated city, town, village,
or any other designated residential or commercial area such as a
subdivision, a business or shopping center, or community development.''
To exist outside of a ``rural area'' as that term is defined under
Sec.  195.2 (i.e., a ``non-rural'' pipeline), a pipeline would have to
be inside (rather than outside) the limits of any incorporated or
unincorporated city, town, etc. Per the definition of an HCA at Sec.
195.450, a pipeline in such an area would be in an HCA, and therefore
would be regulated and subject to assessment requirements. Therefore,
with the exception of regulated rural gathering lines, operators should
be assessing all other regulated gathering lines per their IM programs.
    PHMSA does not agree with API-AOPL that clarification is needed in
the rule on the issue of ``idle'' pipelines. The Federal PSR list only
two statuses for a pipeline: (1) In-service/active; or (2)
``abandoned,'' which the PSR defines as ``permanently removed from
service.'' Although operators frequently refer to a pipeline that is
not being actively used as ``idle,'' PHMSA has no current operational
designation for an ``idle'' line. Unless they are abandoned in
accordance with applicable procedures, pipelines that are not currently
in use must meet all the requirements of the Federal PSR, including
compliance with IM regulations if those pipelines are in HCAs. On March
17, 2014, a pipeline leaked crude oil into a highly populated suburb of
Los Angeles, CA (Wilmington, CA), releasing an estimated 1,200 gallons
of oil.\43\ The pipeline was never purged and filled with inert
material as per the operator's procedures required by the regulations,
and the operator (who bought the pipeline from another operator),
believed the pipeline was ``abandoned.'' This demonstrates the fact
that pipelines that have been ``idled'' can still present a safety risk
and must be treated as active pipelines. Further, as operators can
restart ``idle'' lines and transport product later, it is important
that operators maintain these lines to the same level of safety and
standards as an active, in-service line. Accordingly, PHMSA expects
operators of ``idle'' lines to perform assessments and adhere to all
the applicable regulations based on the line's location.
---------------------------------------------------------------------------

    \43\ Jeff Gottlieb: ``Phillips 66 oil line in Wilmington blamed
for 1,200-gallon spill,'' Los Angeles Times, March 18, 2014. http://articles.latimes.com/2014/mar/18/local/la-me-0319-crude-oil-20140319.
---------------------------------------------------------------------------

    PHMSA considered the requests it received to make inspection
reports for non-HCA lines publicly available and to require third-party
inspection report verification. PHMSA determined that promulgating
those requirements would make assessing non-HCA lines more burdensome
than assessing HCA lines.
    Regarding requests that PHMSA require non-HCA inspections at 5-year
intervals to ensure a larger number of populations and properties are
protected, PHMSA notes that setting the non-HCA assessment interval to
5 years would make it equal to that for lines in HCAs. Lowering the
non-HCA assessment period to any time below 5 years would make it more
stringent than the requirement for HCAs and would not allow operators
to prioritize those higher-consequence areas first. Similarly,
requiring a yearly inspection of all hazardous liquid pipelines, as
some commenters suggested, would be overly burdensome and would work
against risk-based prioritization.
    Many commenters also requested that PHMSA require operators to
perform risk assessments on non-IM pipelines. As discussed in the
previous section on extreme weather events, PHMSA expects operators
will need to have a certain amount of information on their HCA and non-
HCA pipelines, including the environment in which they operate, for
them to properly assess risk and the current condition of their
pipeline system and to select the proper tool(s) for an adequate threat
analysis. Operators cannot properly perform assessments if they do not
know or understand the ``as-is'' state of their pipeline and any
potential or actual threats. This information is required to comply
with Sec.  195.401(a), which states that no operator may operate or
maintain its pipeline systems at a level of safety lower than that
required by subpart F of 49 CFR part 195 and the procedures it is
required to establish under Sec.  195.402(a). Therefore, PHMSA expects
operators will already be performing a level of risk analysis on non-
HCA lines as well as HCA lines.

E. IM and Non-IM Repair Criteria

1.a PHMSA's Proposal for Sec.  195.452 (IM Repairs)
    In the NPRM, PHMSA proposed modifying criteria in Sec.  195.452(h)
for IM repairs to:
     Categorize bottom-side dents with stress risers, pipe with
significant stress corrosion cracking, and pipe with selective seam
weld corrosion as immediate repair conditions;
     Require immediate repairs whenever the calculated burst
pressure is less than 1.1 times MOP;
     Eliminate the 60-day and 180-day repair categories; and
     Establish a new, consolidated 270-day repair category.
1.b PHMSA's Proposal for Sec.  195.422 (Non-IM Repairs)
    PHMSA also proposed to amend the requirements in Sec.  195.422 for
performing non-IM repairs by:
     Applying the criteria in the immediate repair category in
Sec.  195.452(h); and
     Establishing an 18-month repair category for hazardous
liquid pipelines that are not subject to IM requirements.
2. Summary of Public Comment
    Citizen groups and individuals expressed concern with the changes
to the repair timeline categories. The Alliance for Great Lakes et al.
requested that PHMSA maintain the 180-day repair timeframe for all
repairs that are not classified as immediate, and the Pipeline Safety
Trust (PST) did not see justification for the 18-month and
``reasonable'' time frames added for repairing pipelines outside of
HCAs. API-AOPL requested a reasonable timeframe to address repairs in
offshore pipelines that considers the type of repair and permit that
might be involved. ETP recommended that PHMSA change the 270-day and
18-month criteria to 1-year and 2-year criteria to assist operators
with planning, budgeting, and scheduling.
    Enterprise Products Partners suggested specific language to clarify
that Sec.  195.422 would apply only to pipelines not subject to IM
requirements in Sec.  195.452 and those determined not to have the
potential to affect HCAs.

API-AOPL also expressed concern that PHMSA might apply these criteria
beyond non-HCA transmission lines to gravity and gathering lines
located offshore and recommended explicit language to state that Sec.
195.422 does not apply to gravity or gathering lines. The GPA requested
that PHMSA clarify the applicability of this section to out-of-service,
``idle'' pipelines.
    Commenters also asked for additional standards for conditions
triggering repairs. For example, one public safety organization
requested a more stringent standard for the amount of metal loss that
triggers ``immediate repair,'' whereas the Alliance for Great Lakes et
al. recommended that PHMSA establish standards for the prevention,
detection, and remediation of significant stress corrosion cracking and
stress corrosion cracking.
    The IPAA commented that PHMSA did not address whether resources
exist to make the additional repairs that would be required, nor did it
demonstrate a nexus between existing risk and the more conservative
repair requirements that justify the potential costs, especially when
considering regulated gathering lines. The GPA requested documentation
on the basis for requiring the same repair criteria for non-gathering
lines as the repair criteria for pipelines affecting HCAs. Western
Refining recommended that PHMSA exempt pipeline segments that normally
operate at a low pressure from the pressure reduction requirement. API-
AOPL recommended that PHMSA add an immediate repair condition for crack
anomalies at a 70 percent nominal wall thickness and an 18-month repair
condition on dents with corrosion. API-AOPL also recommended that PHMSA
include a ``Scheduled Conditions'' repair condition for non-HCA lines,
which would require an operator to make a report prior to the year when
a calculation of the predicted remaining strength of the pipe
(including allowances for growth and tool measurement error) shows a
predicted burst pressure at less than 1.1 times the MOP at the location
of the anomaly. This recommendation aimed to mitigate the potential for
pressure-limiting, immediate features before the next ILI. Enterprise
Products Partners recommended language to provide operators with
flexibility to determine the severity of the reported metal loss
indication and its potential impact on the integrity of the pipeline by
setting the dent threshold as corroded areas deeper than 20 percent of
the nominal wall thickness or where an engineering analysis indicates a
reduction in the safe operating pressure of the dented area.
    API-AOPL and AGA recommended eliminating the SCC and SSWC immediate
repair criteria. The AGA also requested that PHMSA allow pipeline
operators to prioritize the repair of HCA segments over non-HCA
segments. The GPA was also concerned that PHMSA's definition of SCC was
based on the use of the word ``significant,'' because the term is
subjective and PHMSA's proposed descriptors do not include all the
variables that influence SCC behavior and is therefore very incomplete
for assigning an ``actionable'' status for all instances.
    The PST requested that PHMSA change Sec.  195.563(a) to require
that constructed, relocated, replaced, or otherwise changed pipelines
must have cathodic protection within 6 months instead of 1 year, and
they also requested that PHMSA require operators to know what type of
pipe is in the ground and set the MOP appropriately, or test the pipe
with an appropriate hydrotest to demonstrate a safe MOP.
    During the meeting of February 1, 2016, the LPAC recommended that
PHMSA modify the NPRM to include recognized industry engineering
analysis regarding dents and cracks to determine they are non-injurious
and do not require immediate repair, and to give full and equal
consideration to the stakeholder comments that were considered during
the LPAC discussion.
3. PHMSA Response
    PHMSA appreciates the information provided by the commenters. PHMSA
proposed revisions to the IM repair criteria to provide operators
greater flexibility regarding the repair timeframes for certain
anomalies, provide additional clarification regarding specific anomaly
types, and address pipe cracking issues both the agency and the NTSB
had identified following the incident near Marshall, MI, especially
regarding stress corrosion cracking and selective seam weld corrosion.
PHMSA also proposed to apply these changes with some modifications to
non-HCAs to provide flexibility to operators and allow the risk-based
prioritization of repairs.
    PHMSA notes that the LPAC, with certain suggestions, found the
changes to both the non-HCA repair criteria and the HCA repair criteria
to be cost-effective, practicable, and technically feasible provisions,
and these provisions seemed to have wide stakeholder support following
the ANPRM stage. However, PHMSA determined as part of the review
process that it needs to gather additional data, including with respect
to cost-benefit information, and to assess new technologies and
practices before promulgating the proposed changes for non-HCA
pipelines in this final rule. Based on this, PHMSA has decided to
separate the repair-criteria provisions from this final rule and
intends to issue a supplemental notice of proposed rulemaking where
PHMSA would further analyze developing technology and practices,
anomaly types and repair timeframes, and engineering critical
assessment methods. This path will also provide commenters an
additional opportunity to provide input on an important part of the
regulations. PHMSA will incorporate any relevant discussion it would
have included in this section of this rulemaking when discussing repair
criteria in the supplemental notice. Therefore, for the purposes of
this final rule, PHMSA is retaining the existing non-IM repair language
at Sec.  195.401(b)(1) and the existing IM repair language at Sec.
195.452(h).
    For non-IM pipelines, Sec. Sec.  195.401(b)(1), 195.585, and
195.587 outline the requirements for non-integrity management pipeline
repairs. Section 195.401(b)(1) requires operators that discover any
condition that could adversely affect the safe operation of its
pipeline system, they must correct the condition within a reasonable
time. However, if the condition is of such a nature that it presents an
immediate hazard to persons or property, the operator may not operate
the affected part of the system until it has corrected the unsafe
condition. For IM pipelines, PHMSA expects operators to continue to
follow the existing regulations in Sec. Sec.  195.401(b)(2) and
195.452(h) as they are written and repair the listed anomaly types
within the specified timeframes.

F. Leak Detection Requirements

1. PHMSA's Proposal
    With respect to new hazardous liquid pipelines, PHMSA proposed to
amend Sec.  195.134 to require that all new lines be designed to have
leak detection systems, including pipelines located in non-HCA areas.
    With respect to existing pipelines, 49 CFR part 195 contains
mandatory leak detection requirements for only those hazardous liquid
pipelines that could affect an HCA. Congress included additional
requirements for leak detection systems in section 8 of the 2011
Pipeline Safety Act. That legislation requires the Secretary to submit
a report to Congress, within 1 year of the enactment date, on the use
of leak detection systems, including an analysis of the technical
limitations and the practicability, safety benefits, and

adverse consequence of establishing additional standards for the use of
those systems. Congress authorized the issuance of regulations for leak
detection if warranted by the findings of the report.
    Based on information available to PHMSA including post-accident
reviews and the Kiefner Report, PHMSA believes the need to strengthen
the requirements for leak detection systems is clear. In addition to
modifying Sec.  195.444 to require a means for detecting leaks on all
portions of a hazardous liquid pipeline system including non-HCA areas,
PHMSA proposed that operators perform an evaluation to determine what
kinds of systems must be installed to adequately protect the public,
property, and the environment. The proposed amendment to Sec.  195.11
extended these new leak detection requirements to regulated onshore
gathering lines.
2. Summary of Public Comment
    Trade organizations expressed concerns with requiring operators of
gathering lines and certain non-gathering lines to install and maintain
leak detection systems. The GPA commented that PHMSA's proposal is not
appropriate for gathering lines at this time, citing findings of the
``Liquids Gathering Pipelines: A Comprehensive Analysis'' study,\44\
which concluded that (1) gathering lines present unique challenges to
leak detection technologies; (2) gathering lines are constantly
transition in flow, pressure, and line-packing; (3) benefits do not
justify the cost for leak detection systems applied to gathering lines;
and (4) there is a lack of demonstrated technology to reliably detect
spills. The IPAA noted that PHMSA should not proceed with expanding
leak detection systems because it had not performed an analysis of the
practicability of establishing technically, operationally, and
economically feasible standards for the capability of such systems to
detect leaks, and the safety benefits and adverse consequences of
requiring operators to use leak detection systems. The GPA also
recommended that PHMSA provide relief for short sections of pipeline
less than 1 mile in length and lines located within facilities where
they pose no risk to the public. API-AOPL and OOC requested
clarification that this section would not apply to offshore gathering
lines. The commenters requested implementation periods ranging between
5 years (API-AOPL) and 7 years (GPA). Finally, the Texas Pipeline
Association commented on the cost of complying with this regulation for
lines outside of HCAs and the redirection of resources from high-risk
areas to lower-risk areas that they allege would occur.
---------------------------------------------------------------------------

    \44\ Energy and Environmental Research Center, University of
North Dakota, 2015, https://www.undeerc.org/bakken/pdfs/EERC%20Gathering%20Pipeline%20Study%20Final%20Dec15.pdf.
---------------------------------------------------------------------------

    Citizen groups and other commenters requested minimum standards for
leak detection systems, and applicability to all hazardous liquids
lines. The Pipeline Safety Coalition recommended the inclusion of (1)
all existing hazardous liquids lines and all lines under construction
at rulemaking; (2) prescriptive standards for leak detection
classifications; (3) prescriptive standards for acceptable leak
detection procedures and devices; and (4) standards that are specific
to location, community, and environmentally sensitive areas. The
Alliance for Great Lakes et al. commented that computational pipeline
monitoring systems detect only large ruptures and involve significant
data interpretation and analysis. They expressed concerns regarding the
lack of system standards and guidance on how to assess the
effectiveness of a given leak detection system on a given pipeline due
to significant variations in pipeline design. The Environmental Defense
Center also recommended that automatic shutdown systems be required.
    Beyond requirements for new pipelines, some commenters also
requested a clear schedule for leak detection system for pipelines
undergoing construction. For example, the NTSB urged PHMSA to include
language that specifies a distinct trigger date for leak detection
implementation on pipelines that have already started construction but
would not yet be operational when the new regulation becomes effective.
    During the February 1, 2016, meeting, the LPAC recommended that
PHMSA modify the NPRM to (1) provide a 5-year implementation period for
existing pipelines and a 1-year implementation period for new pipelines
and (2) clarify that the expanded use of leak detection systems is not
applicable to offshore gathering pipelines.
3. PHMSA Response
    PHMSA notes that commenters asserting PHMSA lacks the authority to
require leak detection systems because it did not first conduct a study
of these systems are incorrect. PHMSA did perform a leak detection
study (``Leak Detection Study--DTPH56-11-D000001'' \45\), as required
by section 8 of the 2011 Pipeline Safety Act, and submitted this study
to Congress on December 31, 2012. The study examined what methods and
measures operators were using as leak detection systems and the
limitations of those methods and measures. The study noted that ``due
to the vast mileage of pipelines throughout the Nation, it is important
that dependable leak detection systems are used to promptly identify
when a leak has occurred so that appropriate response actions are
initiated quickly. The swiftness of these actions can help reduce the
consequences of accidents or incidents to the public, environment, and
property.'' The study also noted that ``incidents described as leaks
can also have reported large release volumes.'' Based on the results of
the study, and due to pipeline accidents such as those near Marshall,
MI, and Salt Lake City, UT, which the study referenced, PHMSA concluded
that operators need to have an adequate means for identifying leaks to
better protect the public, property, and the environment. PHMSA
continues to foster leak detection technology improvements through
research and development projects, and PHMSA is also considering
pursuing rupture detection metrics in another rulemaking.
---------------------------------------------------------------------------

    \45\ Kiefner & Associates, Inc.: ``Leak Detection Study,'' Final
Report No. 12-173, DTPH56-11-D-000001, December 10, 2012. http://www.phmsa.dot.gov/staticfiles/PHMSA/DownloadableFiles/Files/Press%20Release%20Files/Leak%20Detection%20Study.pdf.
---------------------------------------------------------------------------

    Recognizing that leak detection technology can be unreliable does
not imply that monitoring and leak detection are without value. The
value of lost product, negative impacts to the environment, loss of
pipeline functionality, spill remediation costs, and public perception
all impact decisions regarding the implementation of leak detection
systems. It is difficult to assign costs to many of these items. PHMSA
expects that the implementation of leak detection systems on non-HCA
pipelines will accelerate leak detection, lead to faster response and
spill containment, and reduce damages from hazardous liquid releases.
    Given this information, PHMSA is finalizing a rule that requires
all new and existing lines, except for gathering lines not subject to
IM, regulated rural gathering lines, and offshore lines, to implement
leak detection systems. Since all lines within HCAs are already subject
to this requirement, the final rule affects pipelines outside of HCAs.

    Commenters and LPAC members made persuasive arguments regarding the
technical challenges that exist for implementing leak detection systems
on offshore gathering lines due to the complex network of gathering
lines coming from offshore platforms and tremendous fluctuations in
flow controlled directly by production platforms. Further, commenters
had concerns that there was not adequate justification for leak
detection requirements on regulated rural gathering lines due to the
lack of incident history. PHMSA did not receive any data or comments
that contradicted these assertions; therefore, PHMSA is not extending
leak detection requirements to offshore gathering lines or regulated
rural gathering lines at this time. However, PHMSA does note that the
LPAC had no objections to extending this requirement to regulated rural
gathering lines and found the provision to be a cost-effective,
practicable, and technically feasible provision. Further, during the
12866 meeting between OIRA and API on December 12, 2016, API presented
data stating that operators agree with PHMSA's assumptions regarding
the use of leak detection systems on non-HCA pipelines. As such, PHMSA
may consider extending leak detection requirements to these lines in
the future.
    PHMSA considered input from the comments and from the LPAC in
setting compliance periods of 1 year for all new lines, and 5 years for
all existing lines. Regarding concerns about compliance periods for
pipelines under construction, PHMSA considers any line that becomes
operational after the publication of this rule to be a new line and
will have 1 year to comply. PHMSA will consider pipelines that are
already operational before the publication of this rule as existing
lines, and those will have 5 years to comply. PHMSA determined that the
specified timelines are reasonable and practicable given that many
operators already implement leak detection systems on their entire
network across both HCA and non-HCA miles, and because many operators
are constructing and designing new lines with leak detection system
capabilities. Further, PHMSA assumes that the cost of extending
existing capabilities to non-HCA miles is minimal for systems already
equipped with SCADA sensors (see the RIA for details).
    Certain commenters questioned the methods of leak detection that
PHMSA would require to comply with this provision. PHMSA notes that
negative pressure wave monitoring, real-time transient modelling, or
other external systems are not necessarily required to comply with the
rule. The costs of using or installing these leak detection system
components were not explicitly analyzed in the RIA; however, operators
may voluntarily choose to use these components, as well as any others,
to comply with the leak detection requirements of the rule.
    PHMSA received several comments regarding leak detection system
performance criteria, valve spacing requirements, and automatic
shutdown capability, which were topics listed in the ANPRM. Due to the
complexity of these topics and the need for further study and public
comment, PHMSA is pursuing these topics in a separate rulemaking.\46\
---------------------------------------------------------------------------

    \46\ ``Pipeline Safety: Amendments to Parts 192 and 195 to
Require Valve Installation and Minimum Rupture Detection
Standards,'' RIN: 2137-AF06.
---------------------------------------------------------------------------

G. Increased Use of ILI Tools in HCAs

1. PHMSA's Proposal
    PHMSA proposed to require that all hazardous liquid pipelines in
HCAs and areas that could affect an HCA be made capable of
accommodating ILI tools within 20 years, unless the basic construction
of a pipeline will not accommodate the passage of such a device. The
current requirements for the passage of ILI devices in hazardous liquid
pipelines are prescribed in Sec.  195.120, which require that new and
replaced pipelines be designed to accommodate in-line inspection tools.
Section 60102(f)(1)(B) of the Pipeline Safety Laws allows the
requirements for the passage of ILI tools to be extended to existing
hazardous liquid pipeline facilities, provided the basic construction
of those facilities can be modified to permit the use of smart pigs.
2. Summary of Public Comment
    Trade organizations expressed concern that the NPRM would inhibit
operators from exercising their expert judgement in selecting an
assessment method and would be overly burdensome. API-AOPL and other
industry representatives requested that PHMSA not adopt this proposal
because it would require pipelines to incur extensive costs due to age,
design, and location of the pipelines, without demonstrating
commensurate benefits. They also requested that PHMSA remove the
requirement to petition for an exemption under Sec.  190.9 and instead
continue to allow operators to exercise their expertise and engineering
judgment in using the most effective and efficient methods of
evaluating the integrity of their facilities with prior notification to
OPS.
    The IPAA and the American Gas Association (AGA) requested that
PHMSA review current studies or conduct an original study to determine
if ILI is appropriate to monitor pipeline corrosion given the current
state of technology. The AGA also requested that PHMSA provide
additional information on what the term ``basic construction'' meant in
the exemption from the ILI-capable requirement.
    Conversely, citizen groups and individuals recommended that
operators use ILI more broadly. An organization representing public
safety and other commenters expressed concern with the length of the
20-year implementation period and the multiple exemptions such as where
the pipe is constructed in such a way that an ILI device cannot be
accommodated. Some of these commenters recommended instead that: (1)
PHMSA significantly reduce the timing of accommodating ILI devices,
perhaps to 5 years; (2) PHMSA require all new pipelines constructed in
HCAs to accommodate ILI devices immediately; (3) PHMSA reexamine and
tighten proposed exemptions; and (4) PHMSA establish standards for ILI
tools, including the detection of stress corrosion cracking.
Congresswoman Capps suggested that PHMSA could establish a shorter time
frame of 5 years with an extension possible upon request with
sufficient evidence for need and a provided plan of action to meet the
standard. The PST recommended that operators integrate close interval
survey results into ILI device findings.
    Other groups commented on the tools used for inspection, the
compliance periods, and accountability. The Environmental Defense
Center requested that PHMSA require other inspection tools and methods,
such as hydrostatic pressure testing, where operators detect certain
types of anomalies and when these technologies can provide additional
information regarding the condition and vulnerabilities of a pipeline
system. The Alliance for Great Lakes et al. recommended that PHMSA
develop a framework that assigns different compliance periods for
pipelines based on factors such as age, leak history, corrosion,
environmental circumstances that could affect the pipeline, and other
aspects such as those typically reviewed in IM studies. Finally,
California Assembly Member Das Williams requested that operators be
required to submit ILI data to PHMSA for review and verification.
    The NTSB recommended that PHMSA require owners/operators to develop
comprehensive implementation plans with transparent progress reporting
of

intermediate milestones to best ensure operators modify existing
pipelines to accommodate the passage of ILI devices within the 20-year
time limit. The NTSB also recommended that operators modify all newly
identified HCA segments to accommodate an internal inspection tool
according to an accelerated schedule, but not more than 5 years after
an operator identifies the HCA.
    During the February 1, 2016, meeting, the LPAC recommended that
PHMSA adopt the proposed 20-year implementation period as feasible and
cost-effective. In a separate vote, the LPAC reached a tie on a 10-year
implementation period, which resulted in a failed motion. The LPAC also
recommended that Sec.  195.452(n) be modified to allow an operator to
file a petition that ILI tools cannot be accommodated when the operator
determines it would abandon or shut down a pipeline as a result of the
cost to comply.
3. PHMSA Response
    PHMSA carefully considered input from commenters and the LPAC in
finalizing this rule, which requires that all HCA pipelines whose basic
construction would accommodate ILI tools be modified to permit the use
of ILI tools within 20 years. Examples of ``basic construction'' that
an operator may be able to show would not accommodate ILI tools include
short length, small diameter, diameter changes, low operating pressure,
low-volume flow, location, sharp bends, and terrain. PHMSA shares the
interest of commenters who requested expeditious upgrades to the
pipeline network to accommodate ILI tools. PHMSA maintains that ILI
tools are generally more effective than other methods at detecting
integrity issues. ILI tools take advantage of state-of-the-art
technological developments and allow operators to identify anomalies
and prioritize anomalies without interrupting services. ILI tools also
provide a higher level of detail than is possible using other testing
tools such as hydrotesting, which allow operators to determine whether
a required safety margin is met (i.e., pass/fail) but do not provide
information about the existence of anomalies that could deteriorate
over time between tests. PHMSA notes that the existing regulation
already requires new pipelines to be capable of accommodating ILI
tools, as certain commenters requested. Data from operators' pipeline
annual reports suggest that the vast majority of pipeline miles are
currently assessed using ILI tools. The mileage not assessed using
these tools is likely to consist of pipeline segments, such as small
diameter pipes, where ILI is impracticable using the current
technologies. Providing sufficient time for ILI tool accommodation
projects allows the industry to prioritize these projects based on age
or other factors, including the risk factors identified by the Alliance
for the Great Lakes in their comments; it also reduces the mileage of
pipeline potentially needing to be replaced before they have reached
their operational life. PHMSA determined that a 20-year timeline
strikes the appropriate balance between the need to make upgrades as
soon as possible to enable more effective integrity assessment
technologies, with the costs and operational practicalities of making
those changes. Given that a preponderance of HCA pipelines can already
accommodate ILI tools, exceptions available for specific pipeline
designs, operational benefits of ILI over other assessment methods, the
continued aging of unpiggable lines, and the 20-year compliance
deadline that will further reduce remaining mileage of old pre-ILI
pipeline, PHMSA determined that the final rule requirement to make
existing HCA pipelines able to accommodate ILI tools is unlikely to
impact any amount of the hazardous liquid pipeline infrastructure.\47\
Accordingly, PHMSA does not estimate any cost for this requirement.
---------------------------------------------------------------------------

    \47\ In the RIA, PHMSA estimates that over 98 percent of
pipelines for which ILI is applicable likely are already able to
accommodate ILI tools. Given the factors listed here, PHMSA assumes
that essentially all HCA lines for which ILII is practicable are
currently, or will be within the next 20 years, piggable. Further
details are in the RIA for this rulemaking.
---------------------------------------------------------------------------

    PHMSA will consider modifying its annual report form to have
hazardous liquid pipeline operators report data on what percentages of
their lines are piggable. In response to commenters who sought more
immediate implementation, PHMSA notes that inability to use ILI on a
pipeline segment does not mean that an operator has not assessed the
pipeline; the regulation requires that these pipelines be assessed
using alternative approaches, with hydrotesting being the most common
alternative. Data reviewed by PHMSA indicates that less than 1 percent
of HCA pipeline mileage is assessed using direct assessment methods.
Comments about seismicity considerations are addressed in the next
section.
    In response to commenters who requested a specific deadline for
making lines in newly identified HCAs capable of accommodating ILI
tools, PHMSA notes that operators will have until the end of the 20-
year implementation period to make lines piggable. Operators who newly
identify HCAs in years 16-20 of the implementation period and after the
20-year implementation period will have 5 years from the date of the
HCA identification to make lines in those areas piggable.

H. Clarifying Other Requirements

1. PHMSA's Proposal
    PHMSA also proposed several other clarifying changes to the
regulations that were intended to improve compliance. First, PHMSA
proposed to revise paragraph (b)(1) of Sec.  195.452 to better
harmonize the current regulations. The existing Sec.  195.452(b)(2)
requires that segments of new pipelines that could affect HCAs be
identified before the pipeline begins operations and Sec.
195.452(d)(1) requires that baseline assessments for covered segments
of new pipelines be completed by the date the pipeline begins
operation. However, Sec.  195.452(b)(1) does not require an operator to
draft its IM program for a new pipeline until 1 year after the pipeline
begins operation. Improved consistency would be beneficial, as the
identification of could affect segments and the performance of baseline
assessments are elements of the written IM program. PHMSA proposed to
amend the table in (b)(1) to resolve this inconsistency by eliminating
the 1-year compliance deadline for Category 3 pipelines. An operator of
a new pipeline would be required to develop its written IM program
before the pipeline begins operation.
    PHMSA proposed to add additional specificity to Sec.  195.452(g) by
establishing several pipeline attributes that must be included in IM
information analyses and to explicitly require that operators integrate
analyzed information to help ensure they are properly evaluating
interacting threats. PHMSA also proposed that operators explicitly
consider any spatial relationships among anomalous information.
    PHMSA also proposed that operators verify their segment
identification annually by determining whether factors considered in
their analysis have changed. The change that PHMSA proposed would not
require that operators automatically re-perform their segment analyses.
Rather, it would require operators to identify the factors considered
in their original analyses, determine whether those factors have
changed, and consider whether any such change would be likely to affect
the results of the original segment

identification. If so, the operator would be required to perform a new
segment analysis to validate or change the endpoints of the segments
affected by the change.
    PHMSA also proposed to add an explicit reference clarifying that
the IM requirements apply to portions of pipeline facilities other than
line pipe. Unlike integrity assessments for line pipe, Sec.  195.452
does not include explicit deadlines for completing the analyses of
other facilities within the definition of ``pipeline'' or for
implementing actions in response to those analyses. While most
operators correctly treat any component that product moves through in
areas that could affect HCAs as subject to IM, PHMSA has reason to
believe that some operators have not completed analyses of their non-
pipe facilities such as pump stations and breakout tanks and have not
implemented appropriate protective and mitigative measures.
    Section 29 of the 2011 Pipeline Safety Act states that ``[i]n
identifying and evaluating all potential threats to each pipeline
segment pursuant to parts 192 and 195 of title 49, Code of Federal
Regulations, an operator of a pipeline facility shall consider the
seismicity of the area.'' While seismicity is already mentioned at
several points in the IM program guidance provided in Appendix C of
part 195, PHMSA proposed to further comply with Congress's directive by
including an explicit reference to seismicity in the list of risk
factors that must be considered in establishing assessment schedules
(Sec.  195.452(e)), performing information analyses (Sec.  195.452(g)),
and implementing preventive and mitigative measures (Sec.  195.452(i))
under the IM requirements.
2. Summary of Public Comment
    Trade organizations commented primarily on the implementation
period for PHMSA's clarifications on data integration and the
attributes and information required. Other trade associations joined
API-AOPL in requesting a 5-year implementation schedule for integrating
these specific attributes, including populating data into information
systems and validating the quality of the data process. The AGA
recommended that PHMSA focus on the analysis of information and
attributes rather than their integration.
    Trade organizations also requested flexibility in developing the
attributes and information required in data analysis. The AGA requested
that operators independently develop the list of information and
attributes to be included in data analysis. They also commented that
there is no current regulatory requirement for an operator of hazardous
liquid or natural gas pipelines to maintain or utilize a GIS.
    Finally, trade organizations expressed concern with changes to the
baseline assessment of newly constructed pipelines. API-AOPL requested
that PHMSA clarify that hydrostatic testing is an acceptable method of
meeting this requirement for new construction.
    During the February 1, 2016, meeting, the LPAC recommended that
PHMSA modify the NPRM to require data integration to begin in year one,
with all attributes completed within 3 years.
3. PHMSA Response
    PHMSA appreciates the information provided by the commenters. As
discussed at the LPAC meeting, integrating data is a key element and
concept of continuous improvement and IM. The requirement that
operators perform data integration has long been a part of IM program
requirements. The attributes that PHMSA proposed in the NPRM were
factors operators should have already been considering when assessing
risk to their pipelines--PHMSA is merely codifying them to better
ensure all operators are utilizing them. PHMSA understands that the
need for some operators to enhance their data systems to fit these
specific attributes will take some time and effort. Because of this,
PHMSA agrees with the LPAC that operators should be given a maximum of
3 years to fully comply and integrate all the proposed attributes into
their data integration systems, with implementation beginning once the
rule is published. However, this implementation period does not mean
operators should lapse in what they are currently required to perform
under Sec.  195.452(g). PHMSA expects operators to add the attributes
issued in this final rule to their current data integration systems and
efforts. While PHMSA is sympathetic to allowing operators more
flexibility with the attributes that should be considered for data
integration, experience has shown that PHMSA needs to prescribe a
common baseline set of attributes for operators to assess.
    PHMSA agrees with commenters who believe hydrostatic testing is an
acceptable baseline assessment method for newly constructed pipelines
and is incorporating that option into this final rule. As operators are
required to conduct hydrostatic tests on all newly constructed
pipelines prior to operation, and PHMSA allows operators to use
hydrostatic testing for subsequent assessments, PHMSA has determined
this could eliminate additional duplicative baseline assessments and
reduce operator burden.

V. PIPES Act of 2016

    On June 22, 2016, the President signed the PIPES Act of 2016,
Public Law 114-183, containing Sections 14 and 25, ``Safety Data
Sheets'' and ``Requirements for Certain Hazardous Liquid Pipeline
Facilities,'' respectively. The language in both Section 14 and Section
25 is self-executing, with Section 25 specifically amending the
Pipeline Safety Act at 49 U.S.C. 60109 by adding new paragraphs (g)
through (g)(4). To allow the timely implementation of these sections of
the PIPES Act of 2016 and to help ensure regulatory certainty, PHMSA
has determined that good cause exists for finding that notice and
comment on these provisions is impracticable and contrary to the public
interest and is subsequently incorporating them into this final rule.
    Section 14 of the PIPES Act of 2016 requires owners and operators
of hazardous liquid pipeline facilities, following accidents involving
pipeline facilities that result in hazardous liquid spills and within 6
hours of a telephonic or electronic notice of the accident to the
National Response Center, to provide safety data sheets on any spilled
hazardous liquid to the designated Federal On-Scene Coordinator and
appropriate State and local emergency responders. PHMSA has
incorporated this requirement in a new Sec.  195.65 under the reporting
requirements of Subpart B.
    Section 25 of the PIPES Act of 2016 applies to operators of any
underwater hazardous liquid pipeline facility located in an HCA that is
not an offshore pipeline facility and any portion of which is located
at depths greater than 150 feet under the surface of the water.
Operators of these facilities, notwithstanding any pipeline integrity
management program or integrity assessment schedule otherwise required
by the Secretary, must ensure that pipeline integrity assessments using
internal inspection technology appropriate for the pipeline's integrity
threats are completed not less often than once every 12 months; and
using pipeline route surveys, depth of cover surveys, pressure tests,
ECDA, or other technology that the operator demonstrates can further
the understanding of the condition of the pipeline facility, ensure
that pipeline integrity assessments are completed on a schedule based
on the risk that the pipeline facility poses to the HCA in which the
pipeline facility is located. PHMSA has incorporated these

requirements in a new Sec.  195.454 as an addition to the pipeline
integrity management requirements under subpart F.

VI. Section-by-Section Analysis

Sec.  195.1 Which pipelines are covered by this part?

    Section 195.1(a) lists the pipelines that are subject to the
requirements in 49 CFR part 195, including gathering lines that cross
waterways used for commercial navigation as well as certain onshore
gathering lines (i.e., those that are in a non-rural area, that meet
the definition of a regulated onshore gathering line, or that are in an
inlet of the Gulf of Mexico). PHMSA has determined it needs additional
information about unregulated gathering lines to fulfill its statutory
obligations, and it has determined it needs additional information
about gravity lines to determine whether any safety regulations need to
be extended to these lines as well. Accordingly, this final rule
extends the reporting requirements in subpart B of part 195 to all
gravity and gathering lines (whether regulated, unregulated, onshore,
or offshore).

Sec.  195.2 Definitions

    Section 195.2 provides definitions for various terms used
throughout part 195. On August 10, 2007, PHMSA published a policy
statement and request for comment on the transportation of ethanol,
ethanol blends, and other biofuels by pipeline (72 FR 45002). PHMSA
noted in the policy statement that the demand for biofuels was
projected to increase in the future because of several Federal energy
policy initiatives, and that the predominant modes for transporting
such commodities (i.e., truck, rail, or barge) would expand over time
to include greater use of pipelines. PHMSA also stated that ethanol and
other biofuels are substances that ``may pose an unreasonable risk to
life or property'' within the meaning of 49 U.S.C. 60101(a)(4)(B) and
accordingly these materials constitute ``hazardous liquids'' for
purposes of the pipeline safety laws and regulations.
    PHMSA is modifying the definition of ``hazardous liquid'' in Sec.
195.2 to conform with 49 U.S.C. 60101(a)(4)(B) and clarify that the
transportation of biofuel by pipeline is subject to the requirements of
49 CFR part 195.

Section 195.3 What documents are incorporated by reference partly or
wholly in this part?

    The incorporation by reference of NACE SP0102 and API RP 1130 was
previously approved by the Director of the Federal Register and is not
changed by this rule.

Section 195.13 What requirements apply to pipelines transporting
hazardous liquids by gravity?

    Section 195.13 is added to subject gravity lines to the same
annual, accident, and safety-related condition reporting requirements
in subpart B of part 195 as other hazardous liquid pipelines.

Section 195.15 What reporting requirements apply to reporting-
regulated-only gathering lines?

    Section 195.15 is added to subject otherwise unregulated rural
gathering lines and certain offshore lines in State waters to the
annual, accident and safety-related condition reporting requirements in
subpart B of part 195 as other hazardous liquid pipelines.

Section 195.65 Safety Data Sheets

    Section 195.65 contains the requirements for providing safety data
sheets on spilled hazardous liquids following accidents. In accordance
with Section 14 of the PIPES Act of 2016, PHMSA is requiring owners and
operators of hazardous liquid pipeline facilities, following accidents
that result in hazardous liquid spills, to provide safety data sheets
on those spilled hazardous liquids to the designated Federal On-Scene
Coordinator and appropriate State and local emergency responders within
6 hours of a telephonic or electronic notice of the accident to the
National Response Center. This is a self-executing provision from the
PIPES Act of 2016 that PHMSA is incorporating into subpart B of the
hazardous liquid pipeline safety regulations.

Section 195.120 Passage of Internal Inspection Devices

    Section 195.120 contains the requirements for accommodating the
passage of internal inspection devices in the design and construction
of new or replaced pipelines. PHMSA has decided that, in the absence of
an emergency, or where the basic construction makes that accommodation
impracticable, a pipeline should be designed and constructed to permit
the use of ILIs. Accordingly, this final rule repeals the provisions in
the regulation that allow operators to petition the Administrator for a
finding that the ILI compatibility requirement should not apply as a
result of construction-related time constraints and problems. The other
provisions in Sec.  195.120 are re-organized without altering the
existing substantive requirements.

Section 195.134 Leak Detection

    Section 195.134 contains the design requirements for computational
pipeline monitoring leak detection systems. The final rule restructures
the existing requirements into paragraphs (a) and (c) and adds a new
provision in paragraphs (b) and (d) to ensure that all newly
constructed, covered pipelines are designed to include leak detection
systems based upon standards in section 4.2 of API 1130 or other
applicable design criteria in the standard.

Section 195.401 General Requirements

    Section 195.401 prescribes general requirements for the operation
and maintenance of hazardous liquid pipelines. PHMSA is modifying the
pipeline repair requirements in Sec.  195.401(b). PHMSA is retaining,
without change, the requirements in paragraphs (b)(1) for non-IM
repairs and (b)(2) for IM repairs. A new paragraph (b)(3) is added,
however, to clearly require operators to consider the risk to people,
property, and the environment in prioritizing the remediation of any
condition that could adversely affect the safe operation of a pipeline
system, no matter whether those conditions are in HCAs or non-HCAs.

Section 195.414 Inspections of Pipelines in Areas Affected by Extreme
Weather and Natural Disasters

    Extreme weather and natural disasters can affect the safe operation
of a pipeline. Accordingly, this final rule establishes a new Sec.
195.414 that requires operators to perform inspections after these
events and to take appropriate remedial actions.

Section 195.416 Pipeline Assessments

    Periodic assessments, particularly with ILI tools, provide critical
information about the condition of a pipeline, but are only currently
required under IM requirements in Sec. Sec.  195.450 through 195.452.
PHMSA has determined that operators should be required to have the
information needed to promptly detect and remediate conditions that
could affect the safe operation of pipelines in all areas. Accordingly,
the final rule establishes a new Sec.  195.416 that requires operators
to perform an assessment, at least once every 10 years, of onshore
pipelines that can accommodate inline inspection tools and that are not
already subject to the IM requirements. This assessment must be
performed for the range of relevant threats to the pipeline segment
using an appropriate ILI tool(s) and

account for uncertainties in reported results. Operators must use a
method capable of assessing seam integrity and corrosion and
deformation anomalies when assessing LF-ERW pipe, lap-welded pipe, or
pipe with a seam factor of less than 1.0. In lieu of performing an ILI
assessment on their lines, operators can perform the assessment by
using a pressure test, external corrosion direct assessment, or other
technology (subject to prior notification, method being able to assess
the threat, and ``no objection'' by PHMSA) that can be demonstrated as
providing an equivalent understanding of the pipe's condition.
    The regulation also requires that the results of these assessments
be reviewed by a person qualified to determine if any conditions exist
that could affect the safe operation of a pipeline; that such
determinations be made promptly, but no later than 180 days after the
assessment; that any unsafe conditions be remediated in accordance with
the repair requirements in Sec.  195.401(b)(1); and that all relevant
information about the pipeline be considering in complying with the
requirements of Sec.  195.416. Consistent with the requirements in the
revised Sec.  195.452(h)(2) regarding the discovery of condition, in
cases where the information necessary to make determination about
pipeline threats cannot be obtained within 180 days following the date
of inspection, pipeline operators must notify PHMSA and provide an
expected date when adequate information will become available.

Section 195.444 Leak Detection

    Section 195.444 contains the operation and maintenance requirements
for Computational Pipeline Monitoring leak detection systems. PHMSA is
amending the PSR so that all covered hazardous liquid pipelines have a
leak detection system. Therefore, the final rule reorganizes the
existing requirements of the regulation into paragraphs (a) and (c),
and adds a new general provision in paragraph (b) that requires
operators to have leak detection systems on all covered pipelines and
to consider certain factors in determining what kind of system is
necessary to protect the public, property, and the environment.

Section 195.452 Pipeline Integrity Management in High Consequence Areas

    Section 195.452 contains the IM requirements for hazardous liquid
pipelines that could affect a HCA in the event of a leak or failure.
The final rule clarifies the applicability of the deadlines in
paragraph (b) for the development of a written program for new
pipelines and low-stress pipelines in rural areas. The rule also makes
the following amendments to paragraphs (c) through (o):
     Paragraph (c)(1)(i)(A) is amended to ensure that operators
consider uncertainty in tool tolerance in reviewing the results of ILI
assessments. The paragraph is also amended to be more consistent with
paragraphs at Sec.  195.416 by stating that pipeline segments with
identified or probable risks or threats related to cracks (such as at
pipe body and weld seams) based on the risk factors specified in
paragraph (e), an operator must use an ILI tool or tools capable of
detecting crack anomalies.
     Paragraph (d) is amended to eliminate obsolete deadlines
for performing baseline assessments and to clarify the requirements for
newly identified HCAs. The deletion of these previous compliance dates
does not change or delete any associated recordkeeping requirements or
implement any new recordkeeping requirements. Operators should retain
the records they have used to show compliance regarding the baseline
assessment deadlines.
     Paragraph (e)(1)(vii) is amended to include local
environmental factors, including seismicity, that might affect pipeline
integrity.
     Paragraph (g) is amended to prescribe certain data points
and criteria that operators must consider in performing the information
analysis required to evaluate periodically the integrity of covered
pipeline segments.
     Paragraph (h)(2) is amended to require that in those
situations where an operator must obtain adequate information within
180 days after an integrity assessment to determine whether an
anomalous condition could present a potential integrity threat of the
pipeline but the operator believes it is impracticable to obtain
sufficient information within that period, the operator must notify
PHMSA and provide an expected date when adequate information will
become available.
     Paragraph (j) is amended to establish a new provision for
verifying the risk factors used in identifying covered segments on at
least an annual basis, not to exceed 15 months.
     A new paragraph (n) is added to require that all pipelines
in areas that could affect an HCA be made capable of accommodating ILI
tools within 20 years, unless, subject to a petition and PHMSA
approval, the basic construction of a pipeline will not permit that
accommodation, the existence of an emergency renders such an
accommodation impracticable, or the operator determines it would
abandon or shut down a pipeline as a result of the cost to comply with
the requirement of this section. Paragraph (n) requires that pipelines
in newly identified HCAs after the 20-year period be made capable of
accommodating ILIs within 5 years of the date of identification or
before the performance of the baseline assessment, whichever is sooner.
     Paragraph (o) is added to allow operators additional time
to integrate the additional information and attributes that PHMSA has
added to the information analysis required under paragraph (g)(1).
     Finally, an explicit reference to seismicity is added to
factors that must be considered in establishing assessment schedules
under paragraph (e), for performing information analyses under
paragraph (g), and for implementing preventive and mitigative measures
under paragraph (i).

Section 195.454 Integrity Assessments for Certain Underwater Hazardous
Liquid Pipeline Facilities Located in HCAs

    Section 195.454 contains additional assessment requirements for
operators of any underwater hazardous liquid pipeline facility located
in an HCA that is not an offshore pipeline facility and any portion of
which is located at depths greater than 150 feet under the surface of
the water. In accordance with section 25 of the PIPES Act of 2016,
PHMSA is requiring these operators to ensure that they complete
pipeline integrity assessments not less often than once every 12 months
using internal inspection technology appropriate for the integrity
threats to the pipeline and complete pipeline integrity assessments
using pipeline route surveys, depth of cover surveys, pressure tests,
external corrosion direct assessment, or other technology that the
operator demonstrates can further the understanding of the condition of
the pipeline facility, on a schedule based on the risk that the
pipeline facility poses to the HCA in which the pipeline facility is
located. This is a self-executing provision from the PIPES Act of 2016
that PHMSA is incorporating into subpart F of the hazardous liquid
pipeline safety regulations.

VII. Regulatory Notices

A. Statutory/Legal Authority for This Rulemaking

    This final rule is published under the authority of the Federal
Pipeline Safety

Law (49 U.S.C. 60101 et seq.). Section 60102 authorizes the Secretary
of Transportation to issue regulations governing design, installation,
inspection, emergency plans and procedures, testing, construction,
extension, operation, replacement, and maintenance of pipeline
facilities, as delegated to the PHMSA Administrator under 49 CFR 1.97.
    PHMSA is revising the ``Authority'' entry for part 195 to include a
citation to a provision of the Mineral Leasing Act (MLA), specifically,
30 U.S.C. 185(w)(3). Section 185(w)(3) provides that ``[p]eriodically,
but at least once a year, the Secretary of the Department of
Transportation shall cause the examination of all pipelines and
associated facilities on Federal lands and shall cause the prompt
reporting of any potential leaks or safety problems.'' The Secretary
has delegated this responsibility to PHMSA (49 CFR 1.97). PHMSA has
traditionally complied with Sec.  185(w)(3) through the issuance of its
pipeline safety regulations, which require annual examinations and
prompt reporting for all or most of the pipelines they cover. PHMSA is
making this change to be consistent with and make clear its long-
standing position that the agency complies with the MLA through the
issuance of pipeline safety regulations.

B. Executive Order 12866 and DOT Regulatory Policies and Procedures

    This final rule is a significant regulatory action under Section
3(f) of Executive Order 12866 (58 FR 51735), and therefore was reviewed
by the Office of Management and Budget. This final rule is significant
under the Regulatory Policies and Procedures of the Department of
Transportation (44 FR 11034) because of substantial congressional,
State, industry, and public interest in pipeline safety.
    In the regulatory analysis, PHMSA discusses the alternatives to the
amended requirements and, where possible, provides estimates of the
benefits and costs for specific regulatory requirements by individual
requirement areas. The regulatory analysis provides PHMSA's best
estimate of the impact of the final rule requirements. As shown in the
table below, PHMSA estimated the total annual costs of the rule at
$19.5 million using a 3 percent discount rate and $21.4 million using a
7 percent discount rate.
    Due to data limitations, PHMSA evaluated the benefits of the final
rule qualitatively. Overall, the rule will provide direct benefits
through avoiding damages from hazardous pipeline incidents that may be
prevented through earlier detection of threats to pipeline integrity
from corrosion or following extreme weather events, and through
enhancing the ability of PHMSA and pipeline operators to evaluate
risks. As context, operator-reported data for hazardous liquid
incidents that occurred between 2010 and 2017 show reported average
annual damages of $91.6 million for pipelines outside HCAs and $265.8
million for pipelines inside HCAs, or about $815 and $3,222 per mile of
hazardous liquid pipeline, respectively. These damages are only a
fraction of the total social costs of hazardous liquid releases but
indicate the potential magnitude of benefits derived from preventing
pipeline failures.
---------------------------------------------------------------------------

    \48\ Numbers in this table may not sum due to rounding.

                         Annualized Costs and Benefits by Requirement Area (2017$) \48\
----------------------------------------------------------------------------------------------------------------
                                                    Annual costs \1\
  Final rule requirement area   --------------------------------------------------------         Benefits
                                      3% Discount rate            7% Discount rate
----------------------------------------------------------------------------------------------------------------
1. Reporting requirements for    $5,000....................  $5,000....................  Better risk
 gravity lines.                                                                           understanding and
                                                                                management.\2\
2. Reporting requirements for    $75,000...................  $76,000...................  Better risk
 gathering lines.                                                                         understanding and
                                                                                management.\3\
3. Inspections of pipelines in   Minimal...................  Minimal...................  Additional clarity and
 areas affected by extreme                                                                certainty for pipeline
 weather events \4\.                                                                      operators.
4. Assessments of onshore        $6,467,000................  $6,467,000................  Avoided incidents and
 pipelines that are not already                                                           damages through
 covered under the IM program                                                             detection of safety
 using ILI every 10 years 5 6.                                                            conditions.\7\
5. IM repair criteria \8\......  $0........................  $0........................  $0.
6. LDSs on pipelines located     $8,652,000................  $10,508,000...............  Reduced damages through
 outside HCAs \6\.                                                                        earlier detection and
                                                                                response.\9\
7. Increased use of ILI tools    Minimal...................  Minimal...................  Improved detection of
 \10\.                                                                                pipeline flaws.\10\
8. Clarify certain IM plan       $4,269,000................  $4,343,000................  Reduced damages through
 requirements..                                                                           prevention and earlier
                                                                                detection and
                                                                                response.\11\
                                --------------------------------------------------------------------------------
    Total......................  $19,468,000...............  $21,399,000...............  Reduced damages from
                                                                                avoiding and/or
                                                                                mitigating hazardous
                                                                                liquid releases.
----------------------------------------------------------------------------------------------------------------
\1\ Costs in this table are rounded to the nearest thousand dollars and may differ from costs presented in
  individual sections of the document. One-time costs are annualized over a 10-year period using discount rates
  of 3 percent and 7 percent.
\2\ Gravity lines can present safety and environmental risks. Depending on the elevation change, a gravity flow
  pipeline could have more pressure than a pipeline with pump stations to boost the pressure. The benefits of
  this requirement are not quantified, but based on social costs of $51 per gallon for releases from regulated
  gathering lines (see Section 2.6.2), the information would need to lead to measures preventing the release of
  101 gallons per year to generate benefits that equal the costs.
\3\ The benefits are not quantified, but based on social costs of $51 per gallon for releases from regulated
  gathering lines (see Section 2.6.2), the information would need to lead to measures preventing the release of
  1,493 gallons per year to generate benefits that equal the costs.
\4\ To the extent that the 72-hour timeline required in the final rule results in higher costs for conducting
  inspections following a disaster (e.g., due to staff overtime), the final rule could result in costs not
  reflected in this analysis.
\5\ PHMSA also conducted a sensitivity analysis that uses alternative baseline assumptions for pipelines not
  currently covered under the IM program. Specifically, PHMSA estimated the costs for two alternative scenarios:
  (1) A scenario that assumes that 100 percent of mileage outside HCAs is assessed in the baseline; and (2) a
  scenario that assumes that 83 percent of the mileage is assessed in the baseline. Costs for these two
  scenarios are $0 and $12.9 million, respectively.
\6\ Excludes gathering lines.
\7\ Given a cost per incident of $536,800, incremental assessment of pipelines outside of HCAs would need to
  prevent 12 incidents for benefits to equate costs.
\8\ PHMSA is not finalizing any changes to the repair criteria and as such expects no incremental costs or
  benefits.

\9\ As discussed in Section 2.6.2, 1,918 incidents involved pipelines outside HCAs between 2010 and 2017, or an
  average of 240 incidents per year. Transmission pipeline incidents outside HCAs had average costs of
  approximately $382,179, not including additional damages and costs that are excluded or underreported in the
  incident data. The annual cost estimate is equivalent to the average damages of 28 to 32 such incidents.
\10\ Costs (to retrofit pipes to accommodate ILI) and benefits (from avoided damages) would accrue only to the
  extent that existing practices deviate from industry standards; PHMSA expects costs and benefits will be
  minimal due to baseline prevalence of ILI-capable pipelines in all areas.
\11\ The benefits of reduced costs associated with the prevention or reduction of released hazardous liquids
  cannot be quantified but could vary in frequency and size depending on the types of failures that are averted.
  Including additional pipelines in the IM plan, integrating data, and conducting spatial analyses is expected
  to enhance an operator's ability to identify and address risk. The societal costs associated with incidents
  involving pipelines in HCAs average $1.7 million per incident (see Section 2.6.2). The annual cost estimates
  for this requirement are equivalent to the average damages from less than three such incidents. This is
  relative to an annual average of 161 incidents in HCAs between 2010 and 2017.

    Overall, factors such as increased safety, public confidence that
all pipelines are regulated, quicker discovery of leaks and mitigation
of environmental damages, and better risk management are expected to
yield benefits that exceed or otherwise justify the costs. A copy of
the final RIA has been placed in the docket. Pursuant to the
Congressional Review Act (5 U.S.C. 801 et seq., the Office of
Information and Regulatory Affairs designated this rule as not a
``major rule,'' as defined by 5 U.S.C. 804(2).

C. Executive Order 13771: Reducing Regulation and Controlling
Regulatory Costs

    The final rule is an Executive Order 13771 regulatory action.
Details on the estimated costs of this final rule can be found in the
rule's economic analysis.

D. Executive Order 13132: Federalism

    This final rule has been analyzed in accordance with the principles
and criteria contained in Executive Order 13132 (``Federalism''). This
final rule does not adopt any regulation that has substantial direct
effects on the states, the relationship between the national government
and the states, or the distribution of power and responsibilities among
the various levels of government. It does not adopt any regulation that
imposes substantial direct compliance costs on state and local
governments. Therefore, the consultation and funding requirements of
Executive Order 13132 do not apply.

E. Regulatory Flexibility Act

    The Regulatory Flexibility Act of 1980 (Pub. L. 96-354) (RFA)
establishes ``as a principle of regulatory issuance that agencies shall
endeavor, consistent with the objectives of the rule and of applicable
statutes, to fit regulatory and informational requirements to the scale
of the businesses, organizations, and governmental jurisdictions
subject to regulation. To achieve this principle, agencies are required
to solicit and consider flexible regulatory proposals and to explain
the rationale for their actions to assure that such proposals are given
serious consideration.''
    The RFA covers a wide range of small entities, including small
businesses, not-for-profit organizations, and small governmental
jurisdictions. Agencies must perform a review to determine whether a
rule will have a significant economic impact on a substantial number of
small entities. If the agency determines that it will, the agency must
prepare a regulatory flexibility analysis as described in the RFA.
    However, if an agency determines that a rule is not expected to
have a significant economic impact on a substantial number of small
entities, section 605(b) of the RFA provides that the head of the
agency may so certify and a regulatory flexibility analysis is not
required. The certification must include a statement providing the
factual basis for this determination, and the reasoning should be
clear.
    PHMSA performed a screening analysis of the economic impact on
small entities. The screening analysis is available in the docket for
the rulemaking. PHMSA estimates that compliance costs may exceed 1
percent of sales for 23 to 31 of the estimated small businesses and may
exceed 3 percent of sales for 9 to 10 small businesses. The higher
number of affected small businesses assumes that the operator incurs
costs for all applicable requirements.
    Given the small number and percentage of small businesses affected,
the small sales test ratios, and the noted flexibility, PHMSA
determined that the final rule will not have a significant impact on a
substantial number of small entities.\49\
---------------------------------------------------------------------------

    \49\ Based on SBA (2013), including criteria developed by other
agencies.
---------------------------------------------------------------------------

    Therefore, I certify that this action does not have a significant
economic impact on a substantial number of small entities.

F. National Environmental Policy Act

    PHMSA analyzed this final rule in accordance with section 102(2)(c)
of the National Environmental Policy Act (42 U.S.C. 4332), the Council
on Environmental Quality regulations (40 CFR parts 1500 through 1508),
and DOT Order 5610.1C, and has determined that this action will not
significantly affect the quality of the human environment. An
environmental assessment of this rulemaking is available in the docket.

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

    This final rule has been analyzed in accordance with the principles
and criteria contained in Executive Order 13175 (``Consultation and
Coordination with Indian Tribal Governments''). Because this final rule
does not have Tribal implications and does not impose substantial
direct compliance costs on Indian Tribal governments, the funding and
consultation requirements of Executive Order 13175 do not apply.

H. 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 estimates the proposals in this rulemaking will impact
the following information collections:
    ``Transportation of Hazardous Liquids by Pipeline: Recordkeeping
and Accident Reporting'' identified under Office of Management and
Budget (OMB) Control Number 2137-0047;
    ``Reporting Safety-Related Conditions on Gas, Hazardous Liquid, and
Carbon Dioxide Pipelines and Liquefied Natural Gas Facilities''
identified under OMB Control Number 2137-0578;
    ``Integrity Management in High Consequence Areas for Operators of
Hazardous Liquid Pipelines'' identified under OMB Control Number 2137-
0605;
    ``Pipeline Safety: Reporting Requirements for Hazardous Liquid
Pipeline Operators: Hazardous Liquid Annual Report'' identified under
OMB Control Number 2137-0614;
    ``National Registry of Pipeline and LNG Operators'' identified
under OMB Control Number 2137-0627; and
    ``Operator Notifications--Alternate Pressure Testing Method''
identified under OMB Control Number 2137-0630.
    PHMSA will submit an information collection revision request to OMB
for

approval based on the requirements in this rule. These information
collections are contained in the Federal Pipeline Safety Regulations,
49 CFR parts 190-199. 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 burden for the following information collections are
estimated to be revised as follows:
    1. Title: Transportation of Hazardous Liquids by Pipeline:
Recordkeeping and Accident Reporting.
    OMB Control Number: 2137-0047.
    Current Expiration Date: 08/31/2020.
    Abstract: This information collection covers the collection of
information from owners and operators of hazardous liquid pipelines. To
ensure adequate public protection from exposure to potential hazardous
liquid pipeline failures, PHMSA collects information on reportable
hazardous liquid pipeline accidents. 49 CFR 195.54 requires hazardous
liquid operators to file an accident report, as soon as practicable,
but not later than 30 days after discovery of the accident, on DOT Form
7000-1 whenever there is a reportable accident the characteristics of
an operator's pipeline system. The final rule will require operators of
both gravity lines and gathering lines to be subject to these accident
reporting requirements. Thus, PHMSA expects an additional 28 HL
pipeline operators (23 gathering line operators and approximately 5
gravity line operators) to be added to the reporting community.
    If the frequency of accidents is the same for non-regulated
gathering lines and gravity lines as it is for transmission lines,
approximately 4 to 6 percent of these newly regulated operators will
submit an accident report in any given year. Of the 23 new gathering
line operators, PHMSA expects 5 accident reports to be filed per year.
Of the 5 new gravity line operators, PHMSA expects 1 accident report to
be filed per year. This results in an added burden of 6 new accident
reports per year at 10 hours per report for a total added burden of 60
hours for accident reporting.
    The final rule will also amend the Pipeline Safety Regulations
(PSR) in 49 CFR 195.65 to require all owners and operators of hazardous
liquid pipeline facilities, following accidents that result in
hazardous liquid spills, to provide safety data sheets on those spilled
hazardous liquids to the designated Federal On-Scene Coordinator and
appropriate State and local emergency responders within 6 hours of a
telephonic or electronic notice of the accident to the National
Response Center. PHMSA expects hazardous liquid operators to file
approximately 406 accident reports per year. This will result in an
added burden of 406 new notifications per year. PHMSA expects that it
will take operators 30 minutes to conduct the required task. This will
result in an added burden of 406 records at .5 hours per record for a
total added burden of 203 hours for safety data sheet notifications
recordkeeping.
    This information collection is being revised to account for the
additional burden that will be incurred because of these new
provisions.
    Affected Public: Owners and operators of hazardous liquid
pipelines.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 1,644.
    Total Annual Burden Hours: 52,692.
    Frequency of Collection: On occasion.
    2. Title: Reporting Safety-Related Conditions on Gas, Hazardous
Liquid, and Carbon Dioxide Pipelines and Liquefied Natural Gas
Facilities.
    OMB Control Number: 2137-0578.
    Current Expiration Date: 8/31/2022.
    Abstract: 49 U.S.C. 60102 requires each operator of a pipeline
facility (except master meter operators) to submit to U.S. DOT a
written report on any safety-related condition that causes or has
caused a significant change or restriction in the operation of a
pipeline facility or a condition that is a hazard to life, property or
the environment.
    This rule will require operators of both gravity lines and
gathering lines to be subject to safety-related condition reporting.
While there is no guarantee that each of the newly covered operators
will incur a safety-related condition, it is a possibility. As a
result, PHMSA plans to include an additional 28 hazardous liquid
pipeline operators (23 gathering line operators and approximately 5
gravity line operators) in this reporting community. PHMSA estimates
that it takes each operator 6 hours to complete a safety-related
condition report. The addition of the 28 newly covered operators will
result in 28 additional responses and an added burden of 168 hours (28
operators * 6 hours).
    This information collection is being revised to account for the
additional burden that will be incurred by newly regulated entities.
Operators currently submitting annual reports will not be otherwise
impacted by this rule.
    Affected Public: Owners and operators of hazardous liquid
pipelines.