[Federal Register Volume 80, Number 197 (Tuesday, October 13, 2015)]
[Proposed Rules]
[Pages 61609-61643]
[FR Doc No: 2015-25359]

Vol. 80

Tuesday,

No. 197

October 13, 2015

Part III

Department of Transportation

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Pipeline and Hazardous Materials Safety Administration

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49 CFR Part 195

 Pipeline Safety: Safety of Hazardous Liquid Pipelines; Proposed Rule

Federal Register / Vol. 80 , No. 197 / Tuesday, October 13, 2015 /
Proposed Rules

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DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous Materials Safety Administration

49 CFR Part 195

[Docket No. PHMSA-2010-0229]
RIN 2137-AE66

Pipeline Safety: Safety of Hazardous Liquid Pipelines

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

ACTION: Notice of proposed rulemaking.

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SUMMARY: In recent years, there have been significant hazardous liquid
pipeline accidents, most notably the 2010 crude oil spill near
Marshall, Michigan, during which almost one million gallons of crude
oil were spilled into the Kalamazoo River. In response to accident
investigation findings, incident report data and trends, and
stakeholder input, PHMSA published an Advance Notice of Proposed
Rulemaking (ANPRM) in the Federal Register on October 18, 2010. The
ANPRM solicited stakeholder and public input and comments on several
aspects of hazardous liquid pipeline regulations being considered for
revision or updating in order to address the lessons learned from the
Marshall, Michigan accident and other pipeline safety issues.
Subsequently, Congress enacted the Pipeline Safety, Regulatory
Certainty, and Job Creation Act that included several provisions that
are relevant to the regulation of hazardous liquid pipelines. Shortly
after the Pipeline Safety, Regulatory Certainty, and Job Creation Act
was passed, the National Transportation Safety Board (NTSB) issued its
accident investigation report on the Marshall, Michigan accident. In
it, NTSB made additional recommendations regarding the need to revise
and update hazardous liquid pipeline regulations.
    In response to these mandates, recommendations, lessons learned,
and public input, PHMSA is proposing to make changes to the hazardous
liquid pipeline safety regulations. PHMSA is proposing these changes to
improve protection of the public, property, and the environment by
closing regulatory gaps where appropriate, and ensuring that operators
are increasing the detection and remediation of unsafe conditions, and
mitigating the adverse effects of pipeline failures.

DATES: Persons interested in submitting written comments on this NPRM
must do so by January 8, 2016. PHMSA will consider late filed comments
so far as practicable.

ADDRESSES: You may submit comments identified by the docket number
PHMSA-2010-0229 by any of the following methods:
    Federal eRulemaking Portal: http://www.regulations.gov. Follow the
online instructions for submitting comments. Fax: 1-202-493-2251.
    Mail: Hand Delivery: U.S. DOT Docket Management System, West
Building Ground Floor, Room W12-140, 1200 New Jersey Avenue SE.,
Washington, DC 20590-0001, between 9 a.m. and 5 p.m., Monday through
Friday, except federal holidays.
    Instructions: If you submit your comments by mail, submit two
copies. To receive confirmation that PHMSA received your comments,
include a self-addressed stamped postcard.

     Note:  Comments are posted without changes or edits to http://www.regulations.gov, including any personal information provided.
There is a privacy statement published on http://www.regulations.gov.

FOR FURTHER INFORMATION CONTACT: Mike Israni, by telephone at 202-366-
4571, by fax at<PHONE_NUMBER>, or by mail at U.S. DOT, PHMSA, 1200 New
Jersey Avenue SE., PHP-30, Washington, DC 20590-0001.

SUPPLEMENTARY INFORMATION:
    Outline of this document:

I. Executive Summary
II. Background and NPRM Proposals
III. Analysis of Advance Notice of Proposed Rulemaking
    A. Scope of Part 195 and Existing Regulatory Exceptions
    B. Definition of High Consequence Area
    C. Leak Detection Equipment and Emergency Flow Restricting
Devices
    D. Valve Spacing
    E. Repair Criteria Outside of High Consequence Areas
    F. Stress Corrosion Cracking
IV. Section by Section Analysis
V. Regulatory Notices and Proposed Changes to Regulatory Text

I. Executive Summary

    In recent years, there have been significant hazardous liquid
pipeline accidents, most notably the 2010 crude oil spill near
Marshall, Michigan, during which almost one million gallons of crude
oil were spilled into the Kalamazoo River. In response to accident
investigation findings, incident report data and trends, and
stakeholder input, PHMSA published an ANPRM in the Federal Register on
October 18, 2010, (75 FR 63774). The ANPRM solicited stakeholder and
public input and comments on several aspects of hazardous liquid
pipeline regulations being considered for revision or updating in order
to address the lessons learned from the Marshall, Michigan accident and
other pipeline safety issues.
    Subsequently, Congress enacted the Pipeline Safety, Regulatory
Certainty, and Job Creation Act of 2011 (Pub. L. 112-90) (The Act).
That legislation included several provisions that are relevant to the
regulation of hazardous liquid pipelines. Shortly after the Act was
passed, NTSB issued its accident investigation report on the Marshall,
Michigan accident. In it, NTSB made additional recommendations
regarding the need to revise and update hazardous liquid pipeline
regulations. Specifically, the NTSB issued recommendations P-12-03 and
P-12-04 respectively, which addressed detection of pipeline cracks and
``discovery of condition''. The ``discovery of condition''
recommendation would require, in cases where a determination about
pipeline threats has not been obtained within 180 days following the
date of inspection, that pipeline operators notify the Pipeline and
Hazardous Materials Safety Administration and provide an expected date
when adequate information will become available.
    The Government Accounting Office (GAO) also issued a recommendation
in 2012 concerning hazardous liquid and gas gathering pipelines.
Recommendation GAO-12-388, dated March 22, 2012, states ``To enhance
the safety of unregulated onshore hazardous liquid and gas gathering
pipelines, the Secretary of Transportation should direct the PHMSA
Administrator to collect data from operators of federally unregulated
onshore hazardous liquid and gas gathering pipelines, subsequent to an
analysis of the benefits and industry burdens associated with such data
collection''.
    In response to these mandates, recommendations, lessons learned,
and public input, PHMSA is proposing to make certain changes to the
Hazardous Liquid Pipeline Safety Regulations. The first and second
proposals are to extend reporting requirements to all hazardous liquid
gravity and gathering lines. The collection of information about these
lines is authorized under the Pipeline Safety Laws, and the resulting
data will assist in determining whether the existing federal and state
regulations for these lines are adequate.
    The third proposal is to require inspections of pipelines in areas
affected by extreme weather, natural disasters, and other similar
events. Such inspections will ensure that pipelines

are still capable of being safely operated after these events. The
fourth proposal is to require periodic inline integrity assessments of
hazardous liquid pipelines that are located outside of HCAs. HCA's are
already covered under the IM program requirements. These assessments
will provide critical information about the condition of these
pipelines, including the existence of internal and external corrosion
and deformation anomalies.
    The fifth proposal is to require the use of leak detection systems
on hazardous liquid pipelines in all locations. The use of such systems
will help to mitigate the effects of hazardous liquid pipeline failures
that occur outside of HCAs. The sixth proposal is to modify the
provisions for making pipeline repairs. Additional conservatism will be
incorporated into the existing repair criteria and an adjusted schedule
will be established to provide greater uniformity. These criteria will
also be made applicable to all hazardous liquid pipelines, with an
extended timeframe for making repairs outside of HCAs.
    The seventh proposal is to require that all pipelines subject to
the IM requirements be capable of accommodating inline inspection tools
within 20 years, unless the basic construction of a pipeline cannot be
modified to permit that accommodation. Inline inspection tools are an
effective means of assessing the integrity of a pipeline and broadening
their use will improve the detection of anomalies and prevent or
mitigate future accidents in high-risk areas. Finally, other
regulations will be clarified to improve certainty and compliance.
PHMSA estimates that 421 hazardous liquid operators may incur costs to
comply with the proposed rule. The estimated annual costs for the
different requirements range from approximately $1,000 to $16.7
million, with aggregate costs of approximately $22.4 million. These
wide ranges exist because the requirements vary widely. For example,
some requirements apply only to pipelines within HCAs, some only to
those outside HCAs, and some to both; other requirements apply only to
onshore pipelines, and others to both on- and offshore; the length of
pipeline, and the number of operators affected both vary for the
different requirements. These proposals are designed to mitigate or
prevent some number of hazardous liquid pipeline incidents resulting in
annualized benefits estimated between approximately $3.5 and $17.7
million, depending on the requirement. 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 considered in this analysis. The dollar value of
fatalities, injuries, and property damages due to pipeline incidents
are societal costs and their prevention represents potential benefits.
The changes proposed in this Notice of Proposed Rulemaking (NPRM) are
expected to enhance overall pipeline safety and protection of the
environment.

II. Background and NPRM Proposals

    Congress established the current framework for regulating the
safety of hazardous liquid pipelines in the Hazardous Liquid Pipeline
Safety Act (HLPSA) of 1979 (Pub. L. 96-129). Like its predecessor, the
Natural Gas Pipeline Safety Act (NGPSA) of 1968 (Pub. L. 90-481), the
HLPSA provides the Secretary of Transportation (Secretary) with the
authority to prescribe minimum federal safety standards for hazardous
liquid pipeline facilities. That authority, as amended in subsequent
reauthorizations, is currently codified in the Pipeline Safety Laws (49
U.S.C. 60101 et seq.).
    PHMSA is the agency within DOT that administers the Pipeline Safety
Laws. PHMSA has issued a set of comprehensive safety standards for the
design, construction, testing, operation, and maintenance of hazardous
liquid pipelines. Those standards are codified in the Hazardous Liquid
Pipeline Safety Regulations (49 CFR part 195).
    Part 195 applies broadly to the transportation of hazardous liquids
or carbon dioxide by pipeline, including on the Outer Continental
Shelf, with certain exceptions set forth by statute or regulation.
Performance-based safety standards are generally favored (i.e., a
particular objective is specified, but the method of achieving that
objective is not). Risk management principles play a critical role in
the IM requirements for HCA's.
    PHMSA exercises primary regulatory authority over interstate
hazardous liquid pipelines, and the owners and operators of those
facilities must comply with safety standards in part 195. The states
may submit a certification to regulate the safety standards and
practices for intrastate pipelines. States certified to regulate their
intrastate lines can also enter into agreements with PHMSA to serve as
an agent for inspecting interstate facilities.
    Most state pipeline safety programs are administered by public
utility commissions. These state authorities must adopt the Pipeline
Safety Regulations as part of a certification or agreement, but can
establish more stringent safety standards for those intrastate pipeline
facilities that they have responsibility to regulate. PHMSA cannot
regulate the safety standards or practices for an intrastate pipeline
facility if a state has a current certification to regulate such
facilities.
    Congress recently enacted the Pipeline Safety, Regulatory
Certainty, and Job Creation Act of 2011 (Pub. L. 112-90) (The Act).
That legislation included several provisions that are relevant to the
regulation of hazardous liquid pipelines. As part of the rulemaking
process, PHMSA presented proposed changes in response to this Act in an
ANPRM published in the Federal Register on October 18, 2010, (75 FR
63774). This NPRM will, in the paragraphs that follow, describe each of
the proposals PHMSA will make along with a statement of need for each
and an explanation of how each of these proposals improve the pipeline
safety regulations.

 Extend Certain Reporting Requirements to All Gravity and Rural
Hazardous Liquid Gathering Lines

    Gravity lines; pipelines that carry product by means of gravity,
are currently exempt from PHMSA regulations. Many gravity lines are
short and within tank farms or other pipeline facilities; however, some
gravity lines are longer and are capable of building up large amounts
of pressure. PHMSA is aware of gravity lines that traverse long
distances with significant elevation changes which could have
significant consequences in the event of a release.
    In order for PHMSA to effectively analyze safety performance and
pipeline risk of gravity lines, PHMSA needs basic data about those
pipelines. The agency has the statutory authority to gather data for
all gravity lines (49 U.S.C. 60117(b)), and that authority was not
affected by any of the provisions in the Pipeline Safety Act of 2011.
Accordingly, PHMSA is proposing to add 49 CFR 195.1(a)(5) to require
that the operators of all gravity lines comply with requirements for
submitting annual, safety-related condition, and incident reports.
PHMSA estimates that, at most, five hazardous liquid pipeline operators
will be affected. Based on comments from API-AOPL to the ANPRM, 3
operators have approximately 17 miles of gravity fed pipelines. PHMSA
estimated that proportionally 5 operators would have 28 miles of
gravity-fed pipelines.
    PHMSA is also proposing to extend the reporting requirements of
part 195 to all hazardous liquid gathering lines. According to the
legislative history, Congress originally opposed any

regulation of rural gathering lines in the Hazardous Liquid Pipeline
Safety Act of 1979 (Pub. L. 96-129) for policy reasons (i.e., those
lines did not present a significant risk to public safety to justify
federal regulation based on the data available at that time). See S.
REP. NO. 96-182 (May 15, 1979), reprinted in 1979 U.S.C.C.A.N. 1971,
1972. However, Congress eventually relaxed that prohibition in the
Pipeline Safety Act of 1992 (Pub. L. 102-508) and authorized the
issuance of safety standards for regulated rural gathering lines based
on a consideration of certain factors and subject to certain
exclusions. When PHMSA adopted the current requirements for regulated
rural gathering lines, the agency made certain policy judgments in
implementing those statutory provisions based on the information
available at that time.
    Recent data indicates, however, 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. 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. The
NTSB has also raised concerns about the safety of hazardous liquid
gathering lines in the Gulf of Mexico and its inlets, which are only
subject to certain inspection and reburial requirements.\1\
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    \1\ https://app.ntsb.gov/news/2010/100624b.html.
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    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,'' \2\ that was performed
by the Oak Ridge National Laboratory and published on May 8, 2015,
PHMSA is proposing additional regulations to ensure the safety of
hazardous liquid gathering lines.
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    \2\ http://www.phmsa.dot.gov/pv_obj_cache/pv_obj_id_7B2B80704EBC3EBABDB5B9F701F184E0854F3600/filename/report_to_congress_on_gathering_lines.pdf.
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    In order for PHMSA to effectively analyze safety performance and
pipeline 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)), and that authority was not
affected by any of the provisions in the Pipeline Safety Act of 2011.
Accordingly, PHMSA is proposing 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.
    In the ANPRM, PHMSA asked whether the agency should repeal or
modify any of the exceptions for hazardous liquid gathering lines.
Section 195.1(a)(4)(ii) states that part 195 applies to a ``regulated
rural gathering line as provided in Sec.  195.11.'' PHMSA adopted a
regulation in a June 2008 final rule (73 FR 31634) that prescribed
certain safety requirements for regulated rural gathering lines (i.e.,
the filing of accident, safety-related condition and annual reports;
establishing the maximum operating pressure according to Sec.  195.406;
installing line markers; and establishing programs for public
awareness, damage prevention, corrosion control, and operator
qualification of personnel).
    The June 2008 final rule did not establish safety standards for all
rural hazardous liquid gathering lines. Some of those lines cannot be
regulated by statute (i.e., 49 U.S.C. 60101(b)(2)(B) states that ``the
definition of `regulated gathering line' for hazardous liquid may not
include a crude oil gathering line that has a nominal diameter of not
more than 6 inches, is operated at low pressure, and is located in a
rural area that is not unusually sensitive to environmental damage.'')
and Congress did not remove this exemption in the 2011 Act. However,
the 2011 Act did require that PHMSA review whether currently
unregulated gathering lines should be made subject to the same
regulations as other pipelines.

Require Inspections of Pipelines in Areas Affected by Extreme Weather,
Natural Disasters, and Other Similar Events

    In July 2011 a pipeline failure occurred near Laurel, Montana,
causing the release of an estimated 1,000 barrels of crude oil into the
Yellowstone River. That area had experienced extensive flooding in the
weeks leading up to the failure, and the operator has estimated the
cleanup costs at approximately $135 million. An instance of flooding
also occurred in 1994 in the State of Texas, leading to the failure of
eight pipelines and the release of more than 35,000 barrels of
hazardous liquids into the San Jacinto River. Some of that released
product also ignited, causing minor burns and other injuries to nearly
550 people according to the NTSB. As the agency has noted in a series
of advisory bulletins, hurricanes are capable of causing extensive
damage to both offshore and inland pipelines (e.g., Hurricane Ivan,
September 23, 2004 (69 FR 57135); Hurricane Katrina, September 7, 2004
(70 FR 53272); Hurricane Rita, September 1, 2011 (76 FR 54531)).
    These 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 is proposing 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, under this proposal an operator must inspect all
potentially affected pipeline facilities post extreme weather event to
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 inspection must occur within 72 hours after the cessation
of the event, or as soon as the affected area can be safely accessed by
the personnel and equipment required to perform the inspection. PHMSA
has found that 72 hours is reasonable and achievable in most cases. If
an adverse condition is found, the operator must take appropriate
remedial action to ensure the safe operation of a pipeline based on the
information obtained as a result of performing the inspection. Such
actions might include, but are not limited to:
     Reducing the operating pressure or shutting down the
pipeline;
     Modifying, repairing, or replacing any damaged pipeline
facilities;
     Preventing, mitigating, or eliminating any unsafe
conditions in the pipeline right-of-ways (ROWS);
     Performing additional patrols, surveys, tests, or
inspections;
     Implementing emergency response activities with federal,
state, or local personnel; and
     Notifying affected communities of the steps that can be
taken to ensure public safety.
    This proposal is based on the experience of PHMSA and is expected
to increase the likelihood that safety

conditions will be found earlier and responded to more quickly. PHMSA
invites comment on this and other proposals in this NPRM. In regard to
this proposal, PHMSA has particular interest in additional comments
concerning how operators currently respond to these events, what type
of events are encountered and if a 72 hour response time is reasonable.

Require Periodic Assessments of Pipelines That Are Not Already Covered
Under the IM Program Requirements

    PHMSA is proposing to require 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 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 inline inspection
(ILI) tool at least once every 10 years. PHMSA needs operators to
complete assessments in HCAs followed by assessments in non-HCAs. Other
assessment methods could be used if an operator provides the Office of
Pipeline Safety (OPS) with prior written notice that a pipeline is not
capable of accommodating an ILI tool. The written notice provided to
PHMSA must include a technical demonstration of why the pipeline is not
capable of accommodating an ILI tool and what alternative technology
the operator proposes to use. The operator must also detail how the
alternative technology would provide a substantially equivalent
understanding of the pipeline's condition in light of the threats that
could affect its safe operation. Such alternative technologies would
include hydrostatic pressure testing or appropriate forms of direct
assessment.
    The individuals who review the results of these periodic
assessments would need to be qualified by knowledge, training, and
experience and would be required to consider any uncertainty in the
results obtained, including ILI tool tolerance, when determining
whether any conditions could adversely affect the safe operation of a
pipeline. Such determinations would have to be made promptly, but no
later than 180 days after an inspection, unless the operator
demonstrates that the 180-day deadline is impracticable.
    Operators would be required to comply with the other provisions in
part 195 in implementing the requirements in Sec.  195.416. That
includes having appropriate provisions for performing these periodic
assessments and any resulting repairs in an operator's procedural
manual (see Sec.  195.402), adhering to the recordkeeping provisions
for inspections, test, and repairs (see Sec.  195.404), and taking
appropriate remedial action under Sec.  195.422, as discussed below.
Section 195.11 would also be amended to subject regulated onshore
gathering lines to the periodic assessment requirement.
    PHMSA believes by proposing the above amendment to the existing
pipeline safety regulations, safety will be increased for all pipelines
both in and out of HCAs. Such a requirement would ensure operators
obtain information necessary for prompt detection and remediation of
corrosion and other deformation anomalies in all locations, not just
HCAs. Currently, operators have indicated that they are performing ILI
assessments on a large majority of their pipelines even though no
regulation requires them to do so outside of HCAs. PHMSA wants to
ensure that current assessment rates continue and expand to those areas
not voluntarily assessed. Of the many methods to assess, PHMSA has
found that ILI in many cases is the most efficient and effective. PHMSA
considered alternatives to its proposal that would likely have lower
overall costs and benefits, but potentially higher net benefits. For
instance, PHMSA considered limiting the proposed expansion of certain
IM requirements to those pipelines where a spill could affect a
building or occupied site such as a playground, or highway. Under this
alternative, pipelines in a location where a spill could not affect a
building, occupied site, or highway would not be subject to these new
requirements. However, this alternative would offer less protection to
the natural environment, including sensitive and protected habitats and
species. PHMSA also considered alternative assessment intervals to the
proposed 10 year interval, such as a 15- or 20-year interval. However,
substantial changes to pipeline integrity can occur in a short
timeframe. PHMSA declined to propose these alternatives because they
would provide fewer benefits than the proposed approach. More
specifically, liquid spills, even in remote areas, can result in
environmental damage necessitating clean up and incurring restoration
costs and lost use and nonuse values. If pipe is not assessed and
repaired in accordance with this proposal, liquid spills are likely to
occur.
    Also, a longer interval between assessments would increase risks of
integrity-related failure compared to PHMSA's proposal. PHMSA was
unable to quantify the benefits and costs of these alternatives due to
limitations in available information, such as the amount of unassessed
pipe where a spill could not affect a building, occupied site, or
highway; the environmental impact of spills from such pipe; and the
incremental reduction in benefit between 10-year and alternative
interval periods. PHMSA seeks public comments on these alternatives,
and the regulatory impact analysis contains specific questions for
public comment on quantifying these alternatives.

 Modify the IM Repair Criteria and Apply Those Same Criteria to Any
Pipeline Where the Operator Has Identified Repair Conditions

    Inspection experience indicates a weakness in current repair
criteria. Specifically, the current repair criteria in non-HCAs
(immediate and reasonable time) does not specify anomaly or repair time
frames. It is left entirely at the operator's discretion. Therefore,
PHMSA is proposing to modify the IM pipeline repair criteria and to
apply the criteria to non-IM pipeline repairs. Specifically, the
criteria in Sec.  195.452(h) for IM repairs would be modified to:
     Categorize bottom-side dents with stress risers as
immediate repair conditions;
     Require immediate repairs whenever the calculated burst
pressure is less than 1.1 times maximum operating pressure;
     Eliminate the 60-day and 180-day repair categories; and
     Establish a new, consolidated 270-day repair category.
    PHMSA is also proposing 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.
    PHMSA believes that these changes will ensure that immediate action
is taken to remediate anomalies that present an imminent threat to the
integrity of hazardous liquid pipelines in all locations. Moreover,
many anomalies that would not qualify as immediate repairs under the
current criteria will meet that requirement as a result of the
additional conservatism

that will be incorporated into the burst pressure calculations. The new
time frames for performing non-immediate repairs will also allow
operators to remediate those conditions in a timely manner while
allocating resources to those areas that present a higher risk of harm
to the public, property, and the environment. The existing requirements
in Sec.  195.422 would also be modified to include a general
requirement for performing all other repairs within a reasonable time.
A proposed amendment to Sec.  195.11 would extend these new pipeline
remediation requirements to regulated onshore gathering lines.
    As a result of these changes, PHMSA would modify the existing
general requirements for pipeline repairs in Sec.  195.401(b).
Paragraph (b)(1) would be modified to reference the new timeframes in
Sec.  195.422(d) and (e) for remediating conditions that could
adversely affect the safe operation of a pipeline segment not subject
to the IM requirements in Sec.  195.452. The requirements in paragraph
(b)(2) for IM repairs under Sec.  195.452(h) will be retained without
change. A new paragraph (b)(3) will be added, however, to 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, including those covered
by the timeframes specified in Sec. Sec.  195.422(d) and (e) and
195.452(h).

Expand the Use of Leak Detection Systems for All Hazardous Liquid
Pipelines

    PHMSA is proposing to amend Sec.  195.134 to require that all new
hazardous liquid pipelines be designed to include leak detection
systems. Recent pipeline accidents, including a pair of related
failures that occurred in 2010 on a crude oil pipeline in Salt Lake
City, Utah, corroborate the significance of having an adequate means
for identifying leaks in all locations. PHMSA, aware of the
significance of leak detection, held two recent workshops in Rockville,
Maryland on March 27-28 of 2012. These workshops sought comment from
the public concerning many of the issues raised in the 2010 ANPRM,
including leak detection expansion. Both workshops were well attended
and PHMSA received valuable input from stakeholders.
    Currently, part 195 contains mandatory leak detection requirements
for hazardous liquid pipelines that could affect an HCA.
    Congress included additional requirements for leak detection
systems in section 8 of the Pipeline Safety Act of 2011. 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. To
provide Congress with an opportunity to review that report, the
Secretary is prohibited from issuing any final leak detection
regulations for a specified time period (i.e., 2 years from the date of
the enactment of the Pipeline Safety Act of 2011, or 1-year after the
submission of the leak detection report to Congress, whichever is
earlier), unless a condition exists that poses a risk to public safety,
property, or the environment, or is an imminent hazard, and the
issuance of such regulations would address that risk or hazard. Other
provisions in part 195 help to detect and mitigate the effects of
pipeline leaks, including the Right of Way (ROW).
    In addition to modifying Sec.  195.444 to require a means for
detecting leaks on all portions of a hazardous liquid pipeline system,
PHMSA is proposing that operators be required to have an evaluation
performed to determine what kinds of systems must be installed to
adequately protect the public, property, and the environment. The
factors that must be considered in performing that evaluation would
include the characteristics and history of the affected pipeline, the
capabilities of the available leak detection systems, and the location
of emergency response personnel. A proposed amendment to Sec.  195.11
would extend these new leak detection requirements to regulated onshore
gathering lines. PHMSA is retaining and is not proposing any
modification to the requirement in Sec. Sec.  195.134 and 195.444 that
each new computational leak detection system comply with the applicable
requirements in the API RP 1130 standard.
    PHMSA does not propose to make any additional changes to the
regulations concerning specific leak detection requirements at this
time. PHMSA will be studying this issue further and may make proposals
concerning this topic in a later rulemaking. PHMSA recently publicly
provided the results of the 2012 Keifner and Associates study of leak
detection systems in the pipeline industry, including the current state
of technology.

Increase the Use of Inline Inspection Tools

    PHMSA is proposing to require that all hazardous liquid pipelines
in HCA's 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 are designed to accommodate
inline inspection tools. The basis for these requirements was a 1988
law that addressed the Secretary's authority with regard to requiring
the accommodation of ILI tools. This law required the Secretary to
establish minimum federal safety standards for the use of ILI tools,
but only in newly constructed and replaced hazardous liquid pipelines
(Pub. L. 100-561).
    In 1996, Congress passed another law further expanding the
Secretary's authority to require pipeline operators to have systems
that can accommodate ILI tools. In particular, Congress provided
additional authority for the Secretary to require the modification of
existing pipelines whose basic construction would accommodate an ILI
tool to accommodate such a tool and permit internal inspection (Pub. L.
104-304).
    As the Research and Special Programs Administration (RSPA), (a
predecessor agency of PHMSA) explained in the final rule April 12, 1994
(59 FR 17275) that promulgated Sec.  195.120, ``[t]he clear intent of
th[at] congressional mandate [wa]s to improve an existing pipeline's
piggability,'' and to ``require[] the gradual elimination of
restrictions in existing hazardous liquid and carbon dioxide lines in a
manner that will eventually make the lines piggable.'' April 2, 1994,
(59 FR 17279). RSPA also noted that Congress amended the 1988 law in
the Pipeline Safety Act of 1992 (Pub. L. 102-508) to require the
periodic internal inspection of hazardous liquid pipelines, including
with ILI tools in appropriate circumstances April 2, 1994, (59 FR
17275). RSPA established requirements for the use of ILI tools in
pipelines that could affect HCAs in the December 2000 IM final rule
December 1, 2000, (65 FR 75378).
    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.

The current requirements apply only to new hazardous liquid pipelines
and to line sections where the line pipe, valves, fittings, or other
components are replaced. Exceptions are also provided for certain kinds
of pipeline facilities, including manifolds, piping at stations and
storage facilities, piping of a size that cannot be inspected with a
commercially available ILI tool, and smaller diameter offshore
pipelines.
    PHMSA is proposing to use the authority provided in section
60102(f)(1)(B) to further facilitate the ``gradual elimination'' of
pipelines that are not capable of accommodating smart pigs. PHMSA would
limit the circumstances where a pipeline can be constructed without
being able to accommodate a smart pig. Under the current regulation, an
operator can petition the PHMSA Administrator for such an allowance for
reasons of impracticability, emergencies, construction time
constraints, and other unforeseen construction problems. PHMSA believes
that an exception should still be available for emergencies and where
the basic construction of a pipeline makes that accommodation
impracticable, but that the other, less urgent circumstances listed in
the regulation are no longer appropriate. Accordingly, the allowances
for construction-related time constraints and problems would be
repealed.
    Modern ILI tools are capable of providing a relatively complete
examination of the entire length of a pipeline, including information
about threats that cannot always be identified using other assessment
methods. ILI tools also provide superior information about incipient
flaws (i.e., flaws that are not yet a threat to pipeline integrity, but
that could become so in the future), thereby allowing these conditions
to be monitored over consecutive inspections and remediated before a
pipeline failure occurs. Hydrostatic pressure testing, another well-
recognized method, reveals flaws (such as wall loss and cracking flaws)
that cause pipe failures at pressures that exceed actual operating
conditions. Similarly, external corrosion direct assessment (ECDA) can
identify instances where coating damage may be affecting pipeline
integrity, but additional activities, including follow-up excavations
and direct examinations, must be performed to verify the extent of that
threat. ECDA also provides less information about the internal
condition of a pipe than ILI tools.
    As with new pipelines, operators will be allowed to petition the
PHMSA Administrator for a finding that the basic construction, (i.e.,
terrain or location, of a pipeline or an emergency) will not permit the
accommodation of a smart pig.

Clarify Other Requirements

    PHMSA is also proposing several other clarifying changes to the
regulations that are intended to improve compliance and enforcement.
First, PHMSA is proposing to revise paragraph (b)(1) of Sec.  195.452
to correct an inconsistency in the current regulations. Currently,
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 one-year after the
pipeline begins operation. These provisions are inconsistent as the
identification could affect segments, and performance of baseline
assessments are elements of the written IM program. PHMSA would amend
the table in (b)(1) to resolve this inconsistency by eliminating the
one-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.
    A decade's worth of IM inspection experience has shown that many
operators are performing inadequate information analyses (e.g., they
are collecting information, but not affording it sufficient
consideration). Integration is one of the most important aspects of the
IM program because it is used in identifying interactions between
threats or conditions affecting the pipeline and in setting priorities
for dealing with identified issues. For example, evidence of potential
corrosion in an area with foreign line crossings and recent aerial
patrol indications of excavation activity could indicate a priority
need for further investigation. Consideration of each of these factors
individually would not reveal any need for priority attention. PHMSA is
concerned that a major benefit to pipeline safety intended in the
initial rule is not being realized because of inadequate information
analyses.
    For this reason, PHMSA is proposing to add additional specificity
to paragraph (g) by establishing a number of pipeline attributes that
must be included in these analyses and to require explicitly that
operators integrate analyzed information. PHMSA is also proposing that
operators consider explicitly any spatial relationships among anomalous
information. PHMSA supports the use of computer-based geographic
information systems (GIS) to record this information. GIS systems can
be beneficial in identifying spatial relationships, but analysis is
required to identify where these relationships could result in
situations adverse to pipeline integrity.
    Second, PHMSA is proposing that operators verify their segment
identification annually by determining whether factors considered in
their analysis have changed. Section 195.452(b) currently requires that
operators identify each segment of their pipeline that could affect an
HCA in the event of a release but there is no explicit requirement that
operators assure that their identification of covered segments remains
current. As time goes by, the likelihood increases that factors
considered in the original identification of covered segments may have
changed. PHMSA believes that operators should periodically re-visit
their initial analyses to determine whether they need to be updated.
New HCAs may be identified. Construction activities or erosion near the
pipeline could change local topography in a way that could cause
product released in an accident to travel further than initially
analyzed. Changes in agricultural land use could also affect an
operator's analysis of the distance released product could be expected
to travel. Changes in the deployment of emergency response personnel
could increase the time required to respond to a release and result in
a larger area being affected by a potential release if the original
segment identification relied on emergency response to limit the
transport of released product.
    The change that PHMSA is proposing would not require that operators
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 analysis to validate or change the endpoints of the
segments affected by the change.
    Third, PHMSA is proposing to clarify, through the use of an
explicit reference that the IM requirements apply to portions of
``pipelines'' 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.
Through IM inspections,

PHMSA has learned 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 Pipeline Safety, Regulatory Certainty, and Job
Creation Act of 2011 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 is proposing 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.

III. Analysis of Advance Notice of Proposed Rulemaking

    On October 18, 2010, (75 FR 63774), PHMSA published an ANPRM asking
the public to comment on several proposed changes to part 195. The
ANPRM sought comments on:
     Scope of part 195 and existing regulatory exceptions;
     Criteria for designation of HCAs;
     Leak detection and emergency flow restricting devices;
     Valve spacing;
     Repair criteria outside of HCAs; and
     Stress corrosion cracking.

The ANPRM may be viewed at http://www.regulations.gov by searching for
Docket ID PHMSA-2010-0229.
    Twenty-one organizations and individuals submitted comments in
response to the ANPRM. The individual docket item numbers are listed
for each comment.

 Associations representing pipeline operators (trade
associations)
    [cir] American Petroleum Institute--Association of Oil Pipelines
(API-AOPL) (PHMSA-2010-0229-0030)
    [cir] Independent Petroleum Association of America (IPAA) (PHMSA-
2010- 0229-0024)
    [cir] Canadian Energy Pipeline Association (CEPA) (PHMSA-2010-0229-
0008)
    [cir] Oklahoma Independent Petroleum Association (OIPA) (PHMSA-
2010- 0229-0018)
    [cir] Texas Pipeline Association (TPA) (PHMSA-2010-0229-0011)
    [cir] Louisiana Midcontinent Oil & Gas Association (LMOGA) (PHMSA-
2010-0229-0018)
    [cir] Texas Oil & Gas Association (TxOGA) (PHMSA-2010-0229-0022)
 Transmission and Distribution Pipeline Companies
    [cir] TransCanada Keystone (PHMSA-2010-0229-0027)
 Government/Municipalities
    [cir] Defense Logistics Agency (DLA) (PHMSA-2010-0229-0016)
    [cir] Metro Area Water Utility Commission (MAWUC) (PHMSA-2010-0229-
0031)
    [cir] North Slope Borough (NSB) (PHMSA-2010-0229-0012)
 Pipeline Safety Regulators
    [cir] National Association of Pipeline Safety Representatives
(NAPSR) (PHMSA-2010-0229-0032)
 Citizens' Groups
    [cir] Pipeline Safety Trust (PST) (PHMSA-2010-0229-0014)
    [cir] Cook Inlet Regional Citizens Advisory Council (CRAC)) (PHMSA-
2010-0229-0019)
    [cir] The Wilderness Society (TWS) (PHMSA-2010-0229-0025)
    [cir] National Resources Defense Council et al. (NRDC) (PHMSA-2010-
0229-0021)
    [cir] Alaska Wilderness League et al. (AKW) (PHMSA-2010-0229-0026)
 Citizens
    [cir] Patrick Coyle (PHMSA-2010-0229-0002)
    [cir] Marian J. Stec (PHMSA-2010-0229-0007)
    [cir] Pamela A. Miller (PHMSA-2010-0229-0013)
    [cir] Anonymous (PHMSA-2010-0229-0005) (The anonymous comment dealt
with quality of drinking water and release permits under the Clean
Water Act.

These topics are beyond the scope of PHMSA's jurisdiction and are not
discussed further).
    Comments are reviewed in the order the ANPRM presented questions
for comment. PHMSA responses to the comments follow.

A. Scope of Part 195 and Existing Regulatory Exceptions

Comments
    API-AOPL, LMOGA, TxOGA, and TransCanada Keystone expressed support
for the gravity line exception. These commenters stated that gravity
lines are short, pose little risk, and are usually located within other
regulated facilities, such as tank farms. NAPSR did not support a
complete repeal of this exception, suggesting there was no data to
support such an action. NAPSR did suggest that the exception should not
apply to ethanol pipelines, which are very susceptible to internal
corrosion.
    MAWUC indicated that gravity lines in HCAs should be regulated
because of the sensitivity of these areas. MAWUC further stated that
these lines (and other rural onshore gathering lines) contain
contaminants that are not present in products carried by other
pipelines, that these contaminants are dangerous to pipeline workers,
and that the impact of releases from these pipelines on the environment
is the same as releases from regulated pipelines.
Response
    PHMSA does not, at this time, intend to repeal the exemption for
gravity lines, but does propose to extend reporting requirements to all
hazardous liquid gravity lines. The collection of information about
these lines is authorized under the Pipeline Safety Laws, and the
resulting data will assist in determining whether the existing federal
and state regulations for these lines are adequate.
Rural Gathering Lines
Comments
    PHMSA received a number of comments on whether to modify or repeal
the requirements in Sec.  195.1(a)(4). API-AOPL, LMOG, IPAA, OIPA, and
TxOGA stated that the regulatory exception for rural gathering lines is
appropriate and should not be repealed or modified. They indicated that
these lines are the source of a small percentage of spills, and that
gathering lines in populated areas and near navigable waterways are
already subject to PHMSA regulation.
    Among citizens' groups, TWS suggested that PHMSA should examine
federal and state release data from all excepted pipelines and regulate
those with release rates similar to currently regulated pipelines. PST
supported expansion of the definition of gathering line to the extent
statutorily possible to capture all lines. Similarly, CRAC, TWS, and
AKW indicated the exception should be removed and regulation expanded
to include produced water lines and production lines. TWS and AKW also
stated that flow lines, which are currently defined by regulation as
production facilities, should be reclassified and regulated as
gathering lines.
    The government/municipalities NSB and MAWUC also commented
concerning the rural gathering line exception. NSB requested PHMSA
place a high priority on removing the

exception for gathering lines. MAWUC supported no gathering line
exceptions in HCAs.
    Citizen Miller commented that PHMSA should regulate production and
produced water lines on Alaska's North Slope, because this area is very
sensitive and includes pristine wetlands and fish and wildlife habitats
of national and international importance. She further commented that
river and coastline pipeline routes and crossings in the Arctic and
subarctic Alaska are particularly of concern due to the rapid change in
permafrost, as well as high rates of coastal erosion which greatly
increases the environmental and human impacts of spills.
Response
    PHMSA believes that the requirements of the Pipeline Safety Act of
2011 and concerns for adequate regulatory oversight can only be
addressed if PHMSA obtains additional information about gathering
lines. PHMSA has the statutory authority to gather data for all
gathering lines (49 U.S.C. 60117(b)), and that authority was not
affected by any of the provisions in the Pipeline Safety Act of 2011.
Accordingly, PHMSA is proposing to amend 49 CFR 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.
Carbon Dioxide Lines
    In the ANPRM, PHMSA asked whether the agency should repeal or
modify the regulatory exception for carbon dioxide pipelines used in
the well injection and recovery production process. Section
195.1(b)(10) states that part 195 does not apply to the transportation
of carbon dioxide downstream from the applicable following point:
    (i) The inlet of a compressor used in the injection of carbon
dioxide for oil recovery operations, or the point where recycled carbon
dioxide enters the injection system, whichever is farther upstream; or
    (ii) The connection of the first branch pipeline in the production
field where the pipeline transports carbon dioxide to an injection well
or to a header or manifold from which a pipeline branches to an
injection well.
Comments
    The trade associations, LMOGA, API-AOPL, OIPA, TxOGA, and IPAA,
commented that PHMSA should not repeal the exception for carbon dioxide
lines used in the well injection and recovery production process. They
indicated the potential risk from a production facility carbon dioxide
pipeline failure is low due to factors of low potential release
volumes, rapid dispersion, and low potential for human exposure. NAPSR
suggested the current exception is appropriate and noted that there is
no data indicating the need for a repeal.
Response
    The regulatory history shows that the exception in Sec.
195.1(b)(10) is limited in scope and only applies to carbon dioxide
pipelines that are directly used in the production of hazardous
liquids. See June 12, 1994, (56 FR 26923) (stating in preamble to 1991
final rule that ``the exception is limited to lines downstream of where
carbon dioxide is delivered to a production facility in the vicinity of
a well site, rather than excepting all the CO2 lines in the broad
expanses of a production field.''); January 21, 1994, (59 FR 3390)
(stating in preamble to June 1994 that agency adopted amendment ``to
clarify that the exception covers pipelines used in the injection of
carbon dioxide for oil recovery operations.''). Congress has indicated
that such facilities should not be subject to federal regulation, and
none of the commenters supported a repeal or modification of this
exception. Accordingly, PHMSA is not proposing to repeal or modify
Sec.  195.1(b)(10).
Offshore Lines in State Waters
    In the ANPRM, PHMSA asked whether the agency should repeal or
modify any of the exceptions for offshore pipelines in state waters.
Comments
    TransCanada Keystone, an industry commenter, and the trade
associations, API-AOPL, LMOGA and TxOGA, stated the current exception
should not be changed. API-AOPL pointed out that PHMSA's jurisdiction
lies only with the transportation of hazardous liquids, not hydrocarbon
production areas of offshore operations. API-AOPL further stated that
changing the state waters exception would unnecessarily add a
duplicative layer of federal regulation.
    The citizens' groups, TWS and AKW, supported removal of this
exemption and increased enforcement in state waters. Likewise, among
the government/municipality comments, NSB indicated that the
regulations need to be expanded to include lines in offshore state
waters. NSB expressed concerns with lack of state enforcement, high
corrosion potential, and the sensitivity of the location of the
offshore lines, such as those in the Beaufort and Chukchi Seas.
    The prohibitions of the Pipeline Safety Act of 2011 do not affect
PHMSA's authority to ensure the safety of offshore gathering lines
under other statutory provisions, including if such a line is hazardous
to life, property, or the environment (49 U.S.C. 60112)). PHMSA also
notes that the generally-applicable limitation in section 60101(a)(22)
of the Pipeline Safety Laws only applies to ``onshore production . . .
facilities,'' and that the states may regulate such intrastate
facilities (see e.g., Tex. Admin. Code Title. 16, sec. 8.1(a)(1)(D)).
Response
    Congress has indicated that additional federal safety standards may
be warranted for offshore gathering lines. First, we would note that
this does not include offshore production pipelines. Section
195.1(b)(5) states that part 195 does not apply to the: Transportation
of hazardous liquid or carbon dioxide in an offshore pipeline in state
waters where the pipeline is located upstream from the outlet flange of
the following farthest downstream facility; the facility where
hydrocarbons or carbon dioxide are produced; or the facility where
produced hydrocarbons or carbon dioxide are first separated,
dehydrated, or otherwise processed.
    RSPA, a predecessor agency of PHMSA, adopted Sec.  195.1(b)(5) in a
June 1994 final rule June 28, 1994, (59 FR 33388). Before that time,
part 195 only included an explicit exception for offshore production
pipelines located on the Outer Continental Shelf. However, as explained
in the preamble to the June 1994 final rule, RSPA believed that the
same exception should be applied to all offshore production pipelines,
including those located in state waters. Under the federal pipeline
safety laws, the agency does not regulate production facilities at all.
Section 21 of the Pipeline Safety Act of 2011 requires the Secretary to
review the existing federal and state regulations for gathering lines
and to submit a report to Congress with the results of that review. A
study on these regulations, titled ``Review of Existing Federal and
State Regulations for Gas and Hazardous Liquid Lines,'' was performed
by the Oak Ridge National Laboratory and was published on May 8, 2015.
The Secretary is also required, if appropriate, to issue regulations
subjecting hazardous liquid gathering lines located offshore and in the
inlets of the Gulf of Mexico to the same safety standards that apply to
all other hazardous gathering lines. Section 21

states that any such regulations cannot be applied to production
pipelines or flow lines.
    Congress also included a provision authorizing the collection of
geospatial or technical data on transportation-related flow lines in
section 12 of the Pipeline Safety Act of 2011. A transportation-related
flow line is defined for purposes of that provision as ``a pipeline
transporting oil off of the grounds of the well where it originated and
across areas not owned by the producer, regardless of the extent to
which the oil has been processed, if at all.'' Section 12 also states
that nothing in that provision ``authorizes the Secretary to prescribe
standards for the movement of oil through production, refining, or
manufacturing facilities or through oil production flow lines located
on the grounds of wells.''
Producer-Operated Pipelines on Outer Continental Shelf
    In the ANPRM, PHMSA asked whether the agency should repeal or
modify any of the exceptions for pipelines on the OCS.
Comments
    TransCanada Keystone, an industry commenter, and the trade
associations, API-AOPL, LMOGA, and TxOGA, stated that the current
exceptions for pipelines on the OCS should remain unchanged. API-AOPL
requested that PHMSA indicate what impact the Bureau of Ocean Energy
Management, Regulation and Enforcement's (BOEMRE) recent publication
regarding Safety and Environmental Management Systems (SEMS) has on
transportation operators. API-AOPL expressed concern that joint
jurisdiction, if created by the recent BOEMRE publication, would result
in regulatory uncertainty.
    NAPSR responded that the exceptions for pipelines on the OCS should
not be changed as these lines are already regulated by the Department
of Interior.
Response
    Section 195.1(b)(6) states that part 195 does not apply to the
transportation of hazardous liquid or carbon dioxide in a pipeline on
the OCS where the pipeline is located upstream of the point at which
operating responsibility transfers from a producting operator to a
transporting operator. Section 195.1(b)(7) further provides that part
195 does not apply to a pipeline segment upstream (generally seaward)
of the last valve on the last production facility on the OCS where a
pipeline on the OCS is producer-operated and crosses into state waters
without first connecting to a transporting operator's facility on the
OCS. Safety equipment protecting PHMSA-regulated pipeline segments is
not excluded. A producing operator of a segment falling within this
exception may petition the Administrator, under Sec.  190.9 of this
chapter, for approval to operate under PHMSA regulations governing
pipeline design, construction, operation, and maintenance. These
exceptions are designed to ensure that a single federal agency is
responsible for regulating the safety of any given pipeline segment on
the OCS (i.e., the Department of Interior for producer-operated
pipelines and PHMSA for transporter-operated pipelines). See final rule
codifying 1976 Memorandum of Understanding (MOU) between the
Departments of Transportation and Interior on the regulation of
offshore pipelines in Sec.  195.1 August 12, 1976 (41 FR 34040); direct
final rule codifying 1996 MOU between the Departments of Transportation
and Interior on the regulation of offshore pipelines in Sec.  195.1
November 19, 1997 (62 FR 61692); and final rule clarifying regulation
of producer-operated pipelines that cross the federal-state boundary in
offshore waters without first connecting to a transporting-operator's
facility on the OCS) August 5, 2003 (68 FR 46109).
    None of the commenters supported the repeal or modification of
Sec.  195.1(b)(6) or (7). Accordingly, PHMSA is not proposing to take
any further action with respect to these two provisions. It should also
be noted that PHMSA is not responsible for administering another
federal agency's statutes or regulations.
Breakout Tanks Not Used for Reinjection or Continued Transportation
    In the ANPRM, PHMSA asked for comment on whether the agency should
expand the extent to which part 195 applies to breakout tanks.
Comments
    PHMSA received several comments on whether the agency should expand
the extent to which part 195 applies to breakout tanks. API-AOPL,
supported by the industry commenter, TransCanada Keystone, and the
trade associations, LMOGA and TxOGA, stated that the current definition
is appropriate, and that PHMSA should review its current MOU with the
Environmental Protection Agency (EPA) before making any changes to
avoid duplicative regulation of these facilities. DLA, a governmental/
municipal entity, echoed the comments of API-AOPL.
    Conversely, NAPSR stated that if PHMSA is referring to the large
number of small tanks that are technically under PHMSA's authority, but
currently not regulated, then this exception should be removed.
Response
    The Pipeline Safety Laws provide PHMSA with broad authority to
regulate ``the storage of hazardous liquid incidental to the movement
of hazardous liquid by pipeline'' (49 U.S.C. 60101(a)(22)(A)). The term
``breakout tank'' is defined in Sec.  195.2 to designate which
aboveground tanks are regulated as breakout under part 195. See Exxon
Corporation v. U.S. Department of Transportation, 978 F.Supp. 946, 949-
54 (E.D. Wash. 1997).
    As some of the commenters noted, PHMSA has an MOU with EPA on the
treatment of breakout tanks and bulk storage tanks under the
requirements of the Oil Pollution Act of 1990. Such agreements can
ensure the effective regulation of facilities that are subject to
regulation by more than one federal agency. As in the case of offshore
pipeline facilities, those agreements can also serve as a guideline on
whether a tank is transportation related or non-transportation related.
    Accordingly, PHMSA will review its agreements with EPA to determine
whether any modifications are necessary, but is not proposing to change
the definition of a ``breakout tank'' in part 195 at this time.
Other Exceptions or Limitations in Part 195
    In the ANPRM, PHMSA asked for comment on whether the agency should
repeal or modify any of the other exceptions in part 195. API-AOPL,
supported by several other trade associations, including LMOGA, TxOGA,
OIPA, and IPAA, commented that the exception in Sec.  195.1(b)(8) for
transportation of hazardous liquid or carbon dioxide through onshore
production (including flow lines), refining, or manufacturing
facilities or storage or in-plant pipeline systems associated with such
facilities should not be changed. API-AOPL commented that these
facilities are not within the scope of the Pipeline Safety Laws,
because they are not typically operated by midstream oil and gas
pipeline companies operating in the pipeline transportation system.
These facilities are already covered under a 1972 MOU with EPA and do
not require further duplicative regulation.
Comments
    API-AOPL commented that the exception in Sec.  195.1(b)(9) for
piping located on the grounds of a materials

transportation terminal used exclusively to transfer products between
non-pipeline modes of transportation should not be changed. This piping
is typically isolated from pipeline pressure by devices that control
pressure in the pipeline under Sec.  195.406(b). TransCanada Keystone,
an industry commenter, supported API-AOPL's comments.
    The citizens' groups NRDC and PST indicated that PHMSA should
establish additional standards for diluted bitumen. Both groups
suggested PHMSA establish additional regulations for that commodity due
to the high temperatures and pressures at which the lines that carry it
operate.
    Both regulatory associations, NAPSR and MAWUC, commented on other
exemptions or limitations of the pipeline safety regulations. NAPSR
indicated that the exemptions for pipelines under 1-mile long that
serve refining, manufacturing, or terminal facilities should be
eliminated for ethanol pipelines. NAPSR also requested that PHMSA
verify that intrastate lines carrying other hazardous liquids, such as
sulfuric acid, are regulated by the states. MAWUC indicated that there
should be no regulatory exceptions in HCA segments, because these areas
must be treated with the highest degree of both prevention and
emergency remediation measures.
    Among government and municipality commenters, NSB stated that Sec.
195.1 should be amended to include regulation of all onshore pipelines
and offshore pipelines in areas of the North Slope. NSB suggests
regulation should occur where the consequences of a hazardous liquid
pipeline failure could adversely impact: (1) An endangered, threatened
or depleted species; (2) subsistence resources and subsistence use
areas; (3) a drinking water supply; (4) cultural, archeological, and
historical resources; (5) navigable waterways (including waterways
navigated by rural residents for the purposes of recreation, commerce,
and subsistence use); (6) recreational use areas; or (7) the
functioning of other regulated facilities. Regulation of all high
pressure, large diameter (6-inch and greater) onshore pipelines and all
offshore pipelines should start at the wellhead.
    One citizen commented that the river and coastline routes in the
Arctic and sub-Arctic are particularly of concern because of the rapid
change in permafrost, as well as high rate of coastal erosion, which
greatly increase the environmental and human impacts of hazardous
liquid spills.
Response
    Section 195.1(b)(8) states that part 195 does not apply to the
transportation of hazardous liquid or carbon dioxide through onshore
production (including flow lines), refining, or manufacturing
facilities or storage or in-plant piping systems associated with such
facilities. That exception is based on section 60101(a)(22) of the
Pipeline Safety Laws, which exempts the movement of hazardous liquid
through onshore production, refining, or manufacturing facilities; or
storage or in-plant piping systems associated with onshore production,
refining, or manufacturing facilities. Accordingly, PHMSA agrees with
the commenters that the exception in Sec.  195.1(b)(8) should not be
changed.
    With respect to the terminal exemption in Sec.  195.1(b)(9)(ii), it
should first be noted that the term ``Pipeline or pipeline system'' is
defined in Sec.  195.2 as ``all parts of a pipeline facility through
which a hazardous liquid or carbon dioxide moves in transportation,
including, but not limited to, line pipe, valves, and other
appurtenances connected to line pipe, pumping units, fabricated
assemblies associated with pumping units, metering and delivery
stations and fabricated assemblies therein, and breakout tanks.'' The
term ``Pipeline facility'' is defined in Sec.  195.2 as ``new and
existing pipe, rights-of-way and any equipment, facility, or building
used in the transportation of hazardous liquids or carbon dioxide.''
Under 49 U.S.C. 60101(a)(22), ``transporting hazardous liquid''
includes ``the storage of hazardous liquid incidental to the movement
of hazardous liquid by pipeline.''
    Section 195.1(b)(9) states that part 195 does not apply to the
transportation of hazardous liquid or carbon dioxide by vessel,
aircraft, tank truck, tank car, or other non-pipeline mode of
transportation or through facilities located on the grounds of a
materials transportation terminal if the facilities are used
exclusively to transfer hazardous liquid or carbon dioxide between non-
pipeline modes of transportation or between a non-pipeline mode and a
pipeline. These facilities do not include any device and associated
piping that are necessary to control pressure in the pipeline under
Sec.  195.406(b).
    One of PHMSA's predecessors, the Materials Transportation Bureau
(MTB), adopted the original version of that exception in a July 1981
final rule July 27, 1981, (46 FR 38357). In excepting the
``[t]ransportation of a hazardous liquid by vessel, aircraft, tank
truck, tank car, or other vehicle or terminal facilities used
exclusively to transfer hazardous liquids between such modes of
transportation,'' MTB stated that: [Its] authority to establish minimum
Federal hazardous liquid pipeline safety standards under the [Hazardous
Liquid Pipeline Safety Act (HLPSA) of 1979] extends to ``the movement
of hazardous liquids by pipeline, or their storage incidental to such
movement.'' The Senate report that accompanied the HLPSA states that,
``It is not intended that authority over storage facilities extend to
storage in marine vessels or storage other than those which are
incidental to pipeline transportation.'' (Sen. Rpt. 96-182, 1st Sess.,
96th Cong. (1979), p. 18.) Earlier laws had vested DOT with extensive
authority to prescribe safety standards governing the movement of
hazardous liquids in seagoing vessels, barges, rail cars, trucks or
aircraft and storage incidental to those forms of transportation. From
the words of the new HLPSA and the related Senate report language, it
is clear that Congress did not want to duplicate or overlap any of
those earlier laws. Thus, HLPSA regulatory authority over storage does
not extend to any form of transportation other than pipeline or to any
storage or terminal facilities that are used exclusively for transfer
of hazardous liquids in or between any of the other forms of
transportation unless that storage or terminal facility is also
``incidental'' to a pipeline which is subject to the HLPSA. These
storage and terminal facilities are expressly excluded from the
coverage of part 195 July 27, 1981, (46 FR 38358). RSPA modified that
exception in the final rule June 28, 1994, (59 FR 33388).
    RSPA, however, continued to maintain the exclusion for the
transportation of hazardous liquids or carbon dioxide by non-pipeline
modes, and added a more detailed exclusion for transfer piping located
on the grounds of a materials transportation terminal.
    The regulatory history demonstrates that the exception in Sec.
195.1(b)(9) is designed to exclude piping used in transfers to non-
pipeline modes of transportation and the facilities and piping at
terminals that are used exclusively for such transfers. The provision
is drafted to ensure that any piping that is not used exclusively to
transfer product between non-pipeline modes or transportation between a
non-pipeline mode and a pipeline and facilities are subject to
regulation by PHMSA. None of the commenters argued in favor of changing
the exception, and there is no information to suggest that such action
is necessary at this time. Accordingly, PHMSA is not

proposing to modify or repeal Sec.  195.1(b)(9).
    With regard to the remaining comments, section 16 of the Pipeline
Safety Act of 2011 requires the Secretary to perform a comprehensive
review of whether the requirements in part 195 are sufficient to ensure
the safety of pipelines that transport diluted bitumen (dilbit) and to
provide Congress with a report on the results of that review. That
review, titled ``Effects of Diluted Bitumen on Crude Oil Transmission
Pipelines,'' was performed by the National Academy of Sciences and was
published in 2013. The review found there were no causes of pipeline
failure unique to the transportation of diluted bitumen, or evidence of
chemical or physical properties of diluted bitumen shipments that are
outside the range of other crude oil shipments, or any other aspect of
diluted bitumen's transportation by pipeline that would make it more
likely than other crude oils to cause releases.\3\ However, the safety
proposals in this rulemaking address all hazardous liquid pipelines,
which include pipelines that transport diluted bitumen.
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    \3\ http://phmsa.dot.gov/staticfiles/PHMSA/DownloadableFiles/Files/Pipeline/Dilbit_1_Transmittal_to_Congress.pdf.
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    Multiproduct petroleum pipelines transporting ethanol blends of up
to 95% are currently regulated by PHMSA under part 195 and no major
ethanol spills have occurred on these pipelines. PHMSA is performing
additional research into the technical issues associated with the
transportation of ethanol by pipeline and will use that information to
determine whether such transportation should be subject to any
additional safety requirements in the future. This NPRM proposes to
conform part 195 with 49 U.S.C. 60101(a)(4) making the transportation
by pipeline of any biofuel that is flammable, toxic, corrosive, or
would be harmful to the environment if released in significant
quantities, subject to part 195.
    The requirements for HCA's are addressed in another portion of this
document. As noted above, PHMSA is proposing to extend the federal
reporting requirements to all hazardous liquid gathering lines (whether
onshore, offshore, regulated, or unregulated).
    In conclusion, PHMSA will not be proposing to change or eliminate
any other regulatory exceptions at this time. The exception for carbon
dioxide pipelines is limited in scope and only applies to production
facilities. Although breakout tanks are defined in a way that limits
the application of part 195, these certain storage tanks may also be
subject to regulation by EPA. PHMSA continues to study the scope of the
gathering line exemptions, but is not proposing to modify these or any
other exemption. At present, nothing indicates that any of the other
exceptions should be modified as part of this rulemaking proceeding, or
that the issuance of regulations for underground storage facilities is
necessary.
Additional Safety Standards for Underground Hazardous Liquid Storage
Facilities
    The definition of a pipeline facility in part 195 includes ``any
equipment, facility, or building used in the transportation of
hazardous liquids . . .'' and, as already noted above, includes storage
terminals. While surface piping in storage fields located at midstream
terminal facilities falls within this definition, part 195 does not
contain comprehensive safety standards for the ``downhole'' underground
hazardous liquid storage caverns. In addition, surface piping at
storage fields located either at the production facility where a
pipeline originates or a destination/consumption facility where a
pipeline terminates would generally not be considered part of the
transportation and, therefore, not be regulated by PHMSA in the manner
that such piping located on the grounds of the midstream terminal
would. RSPA provided an explanation in a July 1997 advisory bulletin
June 2, 1997, (62 FR 37118) which the agency issued in response to a
NTSB recommendation on the regulation of underground storage caverns
(P-93-9). RSPA noted in that advisory bulletin that a recent report
indicated that state regulations applied in some form to significant
percentages of these facilities, and that API had developed a set of
comprehensive guidelines for the underground storage of liquid
hydrocarbons. As result of these state regulations, the API guidelines,
and ``the varying and diverse geology and hydrology of the many sites''
RSPA stated that agency had ``decided that generally applicable federal
standards may not be appropriate for underground storage facilities.''
June 2, 1997, (62 FR 37118) RSPA further stated it would be
``encouraging state action and voluntary industry action as a way to
assure underground storage safety instead of proposing additional
federal regulations.'' Id. PHMSA understands that Court decisions
preempting state from regulating interstate facilities appears to be a
concern for state regulators.
Comments
    PHMSA requested comment on the promulgation of new or additional
safety standards for underground hazardous liquid storage. The industry
commenter, TransCanada Keystone, supported the comments of API-AOPL, as
did the trade associations LMOGA and TxOGA. API-AOPL stated that the
current exclusion of the underground cavern is appropriate as they are
already regulated by the states. API-AOPL indicated that the states are
better suited to regulate these facilities because of their knowledge
of these facilities and locations.
    One government/municipality, DLA, commented that there was no need
for new regulations for underground hazardous liquid storage
facilities. DLA maintains that these facilities are currently regulated
for purposes of the Clean Air Act under both 40 CFR parts 112 and 280
by the EPA.
Response
    None of the commenters supported the issuance of additional
regulations for underground hazardous liquid storage caverns, and there
is no information suggesting that such action is necessary at this
time. Therefore, PHMSA is not proposing to issue any new regulations
for underground storage of hazardous liquids in this proceeding.
Order in Which Regulatory Changes Should Be Made in to Best Protect the
Public, Property, or the Environment
Comments
    PHMSA received comments from industry, trade associations, one
government/municipality, and one regulatory association responding to
the question on the order of the actions PHMSA should take to best
protect the public, property, or the environment. API-AOPL, supported
by TransCanada Keystone and the trade associations, OIPA, TxOGA, and
LMOGA, indicated that PHMSA's actions should be risk-based. Similarly,
NAPSR had no recommendation on the order, but suggested that it be
based on risk.
    The government/municipality NSB requested that PHMSA place a high
priority on the repeal of regulatory exceptions for gathering of
hazardous liquids in rural areas, offshore pipelines in state waters,
and producer-operated lines on the OCS. NSB stated that unregulated
rural pipelines are located in Unusually Sensitive Areas (USAs) of the
NSB. These pipelines cross sensitive arctic tundra vegetation and
impact areas used by endangered species. As North Slope development
continues to expand to the west, east, and south,

impacts to NSB communities and USAs will increase.
Response
    PHMSA is proposing to repeal the exception for gravity lines and to
apply the reporting requirements in part 195 to all gathering lines.

B. Definition of High Consequence Area

    In the ANPRM, PHMSA asked for public comment on whether to modify
the requirements in part 195 for HCAs. Specifically, PHMSA asked
whether:
     The criteria for identifying HCAs should be changed to
incorporate additional pipeline mileage or better reflect risk;
     All navigable waterways should be included within the
definition of an HCA;
     The process for making HCA determinations on pipeline ROWs
can be improved;
     The public and state and local governments should be more
involved in making HCA determinations;
     Additional safety requirements should be developed for
areas outside of HCAs; and
     Major road and railway crossings should be included within
the definition of an HCA.
    As discussed in detail later in the Background and NPRM Proposals
section, PHMSA is proposing to adopt additional safety standards for
pipelines that are located outside of areas that could affect an HCA.
These measures will increase the safety of all of the nation's
pipelines without necessitating any change to the HCA definition;
therefore, PHMSA is not taking any further action on that proposal at
this time.
Expanding the Definition of HCA To Include Additional Pipeline Mileage
    In the ANPRM, PHMSA asked whether the current criteria for
identifying HCAs should be modified to incorporate additional pipeline
mileage.
Comments
    TransCanada Keystone recommended that PHMSA further define the
meaning of an HCA, and that the agency provide greater clarity with
respect to the HCA classification, including the magnitude of impacts
that differentiate HCAs from other areas.
    API-AOPL, supported by the trade associations, TxOGA and LMOGA, and
an industry commenter, TransCanada Keystone, stated that the current
criteria should not be changed. API-AOPL stated that PHMSA should serve
a clearinghouse function by displaying HCA information on the NPMS,
with updates every 10 years based on census information. API-AOPL
further noted that ``other populated areas'' includes Census-delineated
areas, like Metropolitan Statistical Areas (MSA) and Consolidated
Metropolitan Statistical Areas, which are not densely populated, and
that the current HCA criteria are thus conservative. API-AOPL also
stated that the current ability of operators to demonstrate why
segments of pipeline could not affect an HCA should be retained.
    The trade associations, OIPA and TPA, suggested that more data is
needed to make a decision on HCA definition expansion, and that any
changes would likely impact small operators.
    Among citizens' groups, PST favored expanding the IM requirements
to all hazardous liquid lines, with initial inspections required within
5 years of identification. PST stated that using census data to
designate high population and other population areas is arbitrary and
not necessarily a predictor of risk. Noting that the public could not
fully comment because HCA boundaries are not publicly available (for
security reasons); PST stated that the definition of HCA should be
expanded to include national parks, monuments, recreation areas, and
national forests. PST also pointed to the recent trend in extreme
accidents in HCAs.
    Two other citizens' groups, AKW and NRDC, commented. AKW requested
that the criteria be changed. NRDC indicated that PHMSA should have a
broader definition of HCAs, particularly with respect to ecological
resources and drinking water criterion.
    NAPSR commented that the current criteria are generally adequate,
but that other threats and risks could be considered, including
petroleum product supply loss, leaks that could affect private wells,
and impacts to major infrastructure.
    NSB favored an expansion of HCAs to include pipelines located in
subsistence areas, cultural resources, archeological, historical, and
recreational areas of significance and offshore.
Response
    Congress recently directed the Secretary to prepare a report on
whether the IM requirements should be extended to pipelines outside of
areas that could affect HCAs. The Secretary is prohibited from issuing
any final regulations that would expand those requirements during a
subsequent Congressional review period, unless those regulations are
necessary to address a condition posing a risk to public safety,
property, or the environment, or an imminent hazard. PHMSA is preparing
the Secretary's report to Congress on the need to expand the IM
requirements and is not proposing to change the definition of an HCA to
incorporate additional pipeline mileage at this time.
    PHMSA is, however, proposing to adopt additional safety standards
for pipelines that are not covered under the IM program requirements.
The proposals are detailed later in this NPRM under the Background and
NPRM proposals section.
    PHMSA is aware of its obligation to consider other locations near
pipeline ROWs in defining USAs, including ``critical wetlands, riverine
or estuarine systems, national parks, wilderness areas, wildlife
preservation areas or refuges, wild and scenic rivers, or critical
habitat areas for threatened and endangered species.'' However, PHMSA
is not proposing to make any of these areas USAs in light of the new
requirements that are being proposed for non-IM pipelines. PHMSA will
be considering whether to include these locations in the HCA definition
in performing the evaluation required under section 5 of the Pipeline
Safety Act of 2011 and will comply with the applicable provisions of
that legislation before taking any final regulatory action to adopt the
proposed requirements for non-IM pipelines.
Modifying the Definition of HCA to Better Reflect Risk
    PHMSA asked whether the criteria for identifying HCAs should be
changed to better reflect risk.
Comments
    TransCanada Keystone's comment focused specifically on the
classification of groundwater USAs in Sec.  195.6, stating that
groundwater HCA buffers should not be expanded, and that the existing
criteria, which identify community water intakes where contamination
has the potential to cause greater impacts compared to other areas, are
sufficient.
    API-AOPL stated that there are various risk factors applicable to
HCA classifications and that the current definition should not be
changed. API-AOPL recommended that buffer zones be used as an
acceptable alternative to the more detailed ``could affect'' analysis
for new, expanded, or modified HCAs. API-AOPL also suggested that
operators should retain the ability, with technical justification, to
determine whether a pipeline can actually impact an HCA. TransCanada
Keystone, LMOGA, and TxOGA endorsed API-AOPL's comments. TPA, the other
trade association commenter, mentioned that

more data was needed to make a final decision on this matter.
    A number of citizens' groups commented on this issue. NRDC, AKW,
and TWS indicated the HCA definition needs to be broadened to reflect
risk and to include entire pipelines in some cases. NRDC stated that
the threshold for a populated area should be lowered, and that the
definition of populated areas and USA should be improved. NRDC
commented that the current HCA definition provides limited protection
to threatened or endangered species. NRDC also recommended
strengthening the USA definition to protect more migratory bird areas
and national landmarks, including national parks, wild and scenic
rivers, estuaries, wilderness areas, wildlife refuges, and drinking
water sources, including private wells and open source aquifers. TWS
and AKW proposed to revise the HCA criteria to include all
transportation infrastructure, public lands, waterways, wetlands, and
cultural, historic, archeological, and recreation sites, including
subsistence areas.
    NAPSR stated that the current HCA definition should not be changed,
but that PHMSA should consider incorporating others threats and risks,
including supply interruptions and small leaks that could affect
private wells.
    NSB favored changing the existing HCA definition. NSB stated that
USAs should include subsistence, cultural, archeological, historical,
and recreational areas of significance within the NSB and offshore
waters of the Beaufort and Chukchi Seas. NSB suggested a formal process
for nominating areas that should be afforded HCA status, and that the
NPMS data should be updated.
    Both MAWUC and DLA indicated the definition could be modified to
better reflect risk. MAWUC suggested a tiered, prioritized system with
enforceable criteria that are appropriate for the risk to water
supplies. DLA stated that higher risk locations should be protected
instead of simply creating more HCAs.
Response
    PHMSA is not proposing to make any changes to the criteria for
identifying HCAs at this time. The existing Census-based approach for
determining high population and other populated areas ensures
uniformity and provides an adequate margin of safety by including some
less densely populated areas. None of the commenters offered a more
effective alternative.
    PHMSA recognizes that other areas of ecological, cultural, or
national significance could be designated as USAs. However, PHMSA is
not proposing to add any of these areas in light of the new safety
standards that are being proposed for hazardous liquid pipelines that
are not subject to the IM program requirements.
    PHMSA does not support any of the suggested alternative approaches
for identifying HCAs. The widespread use of the buffer method is not
justified based on the available information, and the use of a more
lenient standard in making HCA determinations would not provide
adequate protection for these sensitive areas. PHMSA will revisit these
conclusions in preparing the Secretary's report to Congress on
expanding the IM program for hazardous liquid pipelines.
Commercial Limitation on Navigable Waterways
    The ANPRM posed the question of expansion of the definition of HCAs
beyond commercially navigable waterways.
Comments
    Several trade associations, API-AOPL, OIPA, and IPAA, and one
industry representative, TransCanada Keystone, opposed expanding the
HCA definition beyond commercially navigable waterways. These
commenters stated that the vast majority of surface waters are already
covered under the present criteria. TPA stated that adopting a
navigable waters standard would make every creek an HCA, resulting in a
significant increase in the burden associated with implementing IM
requirements.
    Two citizens' groups commented on the phrase ``commercially
navigable.'' PST also recommended defining HCA to include all ``waters
of the United States,'' provided PHMSA did not adopt its suggestion to
apply IM requirements to all regulated pipelines. NRDC proposed to
amend the term ``commercially navigable waterways'' to include other
bodies of water that are not necessarily navigable, such as lakes,
streams, and wetlands.
    Two government/municipalities commented on the commercial
limitation on navigable waterways. DLA, a government/municipality,
echoed the comments of the trade associations and TransCanada Keystone
previously mentioned. NSB requested PHMSA change commercially navigable
to ``navigable waters'' or ``waters of the U.S.'' to encompass more
environmentally-sensitive areas.
Response
    Section 195.450 states that an HCA includes any ``waterway where a
substantial likelihood of commercial navigation exists.'' RSPA first
proposed to include commercially navigable waterways as HCAs in the
April 2000 NPRM that contained the original IM requirements for
hazardous liquid pipelines April 24, 2000, (65 FR 21695). RSPA stated
that it ``[wa]s including commercially navigable waterways in the
proposed [HCA] definition[,] [b]ecause these waterways are critical to
interstate and foreign commerce and supply vital resources to many
American communities, are a major means of commercial transportation,
and are a part of a national defense system, a pipeline release in
these areas could have significant impacts.'' April 24, 2000, (65 FR
21700).
    RSPA adopted the HCA definition as proposed in the NPRM in the
final rule December 1, 2000, (65 FR 75378). In the preamble to that
final rule, RSPA stated that it had received the following comments on
its proposal to include commercially navigable waterways in the HCA
definition:
    API and liquid operators questioned the inclusion of commercially
navigable waterways into the HCA's definition. API pointed out that
Congress required OPS to identify hazardous liquid pipelines that cross
waters where a substantial likelihood of commercial navigation exists
and once identified, issue standards, if necessary, requiring periodic
inspection of the pipelines in these areas. API said that OPS had not
determined the necessity for including these waterways in areas that
trigger additional integrity protections. BP Amoco said the rule should
be limited to protection of public safety, rather than commercial
interests. Enbridge and Lakehead also questioned why waterways that are
not otherwise environmentally sensitive should be included for
protection.
    EPA Region III said that we should also consider recreational and
waterways other than those for commercial use. Environmental Defense,
Batten, City of Austin and other[s] commented that we should consider
all navigable waterways as HCA's, because of the environmental
consequences a hazardous liquid release could have on such waters.
December 1, 2000, (65 FR 75390).
    RSPA provided the following response to those comments:
    ``Our inclusion of commercially navigable waterways for public
safety and secondary reasons is not based on the ecological sensitivity
of these

waterways. Parts of waterways sensitive for ecological purposes are
covered in the proposed USA definition, to the extent that they contain
occurrences of a threatened and endangered species, critically
imperiled or imperiled species, depleted marine mammal, depleted multi-
species area, Western Hemispheric Shorebird Reserve Network or Ramsar
site. We are including commercially navigable waterways as HCAs because
these waterways are a major means of commercial transportation, are
critical to interstate and foreign commerce, supply vital resources to
many American communities, and are part of a national defense system. A
pipeline release could have significant consequences on such vital
areas by interrupting supply operations due to potentially long
response and recovery operations that occur with hazardous liquid
spills. December 1, 2000, (65 FR 75391-2).
    For these reasons, RSPA defined HCAs in Sec.  195.450 to include
commercially navigable waterways.
    Thus, the Pipeline Safety Laws do not necessarily limit the
definition of an HCA to commercially navigable waterways. RSPA relied
on several statutes in promulgating the IM requirements for hazardous
liquid pipelines, including the mandates that required the Secretary to
establish criteria for identifying pipelines in high density population
and environmentally sensitive areas (49 U.S.C. 60109(a)(1)) and to
promulgate standards for ensuring the periodic inspection of these
lines (49 U.S.C. 60102(f)(2)). Nothing in these provisions or the
Pipeline Safety Act of 2011 prohibits PHSMA from using its general
rulemaking authority to apply the hazardous liquid pipeline IM
regulations to waterways that are not used for commercial navigation.
Other kinds of waterways are also referenced in the statutory criteria
that must be considered in defining USAs.
    PHMSA will be considering the expansion of current HCA or the
extension of critical IM requirements to non-HCAs-when completing the
Secretary's report to Congress on the need to expand the IM requirement
under section 5 of the Pipeline Safety Act of 2011. In the meantime,
PHMSA is not proposing to include any additional waterways in the HCA
definition.
    PHMSA is, however, proposing to adopt other regulations that will
increase the safety of our nation's waterways. One such proposal is to
require leak detection systems for pipelines in all locations, that
operators perform periodic assessments of pipelines not already covered
under the IM program requirements, and that new pipeline repair
criteria be applied to anomalous conditions discovered in all areas.
Another proposal is to require operators to inspect their pipelines in
areas affected by extreme weather, natural disasters, and other similar
events (e.g., flooding, hurricanes, tornados, earthquakes, landslides,
etc.). Following a disaster event, operators will be required to
determine whether any conditions exist that could adversely affect the
safe operation of a pipeline and to take appropriate remedial actions,
such as reductions in operating pressures and repairs of any damaged
facilities or equipment.
    In regard to seismic events and earthquakes, in determining whether
a pipeline has potentially been affected and needs inspection,
operators should consider relevant factors such as magnitude of the
earthquake, distance from the epicenter, and pipeline characteristics
and history. PHMSA recognizes that after considering these factors,
operators may determine that smaller seismic events do not have the
potential to affect their pipelines. Based on available studies,
however, earthquakes over 6.0 in magnitude can potentially damage
pipelines and operators would be required to inspect these pipelines.
Operator Process and Public Participation in Making HCA Determinations
    PHMSA requested comment on whether the operator's process for
making HCA determinations should be modified, including by having
greater involvement by the public and state and local governments.
Comments
    PHMSA received comments from industry, trade associations, and one
regulatory association. API-AOPL supported the existing process for
identifying HCAs and suggested that any input from local communities
should be through the regulating agency, rather than pipeline
operators. OPIA and IPAA noted that a consistent and reliable approach
is needed to prevent variations that would result in unnecessary
confusion.
    The trade associations, TxOGA, LMOGA, API-AOPL, supported by
TransCanada Keystone, indicated that operators perform geographic
overlay of their pipeline systems with PHMSA-determined HCAs. Operators
also utilize the ``could affect'' analysis, which typically considers
technical assessments using dispersion models. Through the process of
HCA evaluation, operators are sometimes able to determine, with
technical justification, that their assets are not capable of impacting
an HCA.
    NAPSR indicated that PHMSA could consider adding minimum time
intervals for operators to review HCA identifications, including a
shorter time interval if a pipeline is routed through high population
areas. NAPSR also stated that there are areas where private wells have
been extremely affected by small leaks that go undetected for years,
that this is especially true in areas of sandy soil where leaks do not
necessarily bubble up to the surface, and that there should be some
consideration to address these ``seepers'' that have very large total
leak volume over time.
    On the matter of greater public participation, TransCanada Keystone
suggested that PHMSA collect data from the states and provide updated
HCA information for operator use. The trade associations, LMOGA, TxOGA
and API-AOPL, supported by TransCanada Keystone, recommended that
additional local involvement be routed through the regulating agency,
such as PHMSA. TPA, in contrast, stated that there should be no
requirement for public involvement. OIPA and IPAA held that a
consistent and reliable approach is needed for the issue of public
involvement.
    Among the citizens' groups, NRDC supported additional public
involvement. Several commenters, including NRDC, PST, and TWS,
recommended that the NPMS be revised to display all HCAs so that the
public can be better informed.
    One regulatory association, NAPSR, suggested that the public be
allowed to comment. NAPSR recognized that PHMSA has a process in place
for HCA selection that can be enhanced if the public is allowed to
provide input. NAPSR stated that the general public and local
communities often recognize changes in areas near pipelines before
operators.
    Government and municipal commenters supported local involvement in
the HCA determination process. MAWUC commented that it is important
that local communities and water suppliers play a role in preventing
and minimizing pipeline failures, including HCA identification. DLA
also supported additional public involvement. NSB recommended that
state and local governments, as well as local tribes, villages, and the
Alaskan Eskimo Whaling Commission, have a role in making HCA
determinations.

Response
    Congress included new requirements for promoting public education
and awareness in section 6 of the Pipeline Safety Act of 2011.
Specifically, that provision requires PHMSA (1) to maintain, and update
on a biennial basis, a map of designated HCAs in the NPMS; (2) to
establish a program that promotes greater awareness of the existence of
the NPMS to state and local emergency responders and other interested
parties, to include the issuance of guidance on using the NPMS to
locate pipelines in communities and local jurisdictions; and (3) to
issue additional guidance to owners and operators of pipeline
facilities on the importance of providing system-specific information
to emergency response agencies. PHMSA believes that such actions will
address many of the concerns raised by the commenters.
Additional Safety Requirements for Non-HCA Areas
    PHMSA inquired as to whether additional safety measures should be
developed for areas outside of HCAs.
Comments
    PHMSA received comments from three trade associations and one
regulatory association. TransCanada Keystone, TxOGA, API-AOPL, and
LMOGA indicated that no new requirements are necessary for areas
outside of HCAs. The regulatory association, NAPSR, remarked that
operators should be precluded from turning off in-line inspection
sensors outside of an HCA when performing an integrity assessment under
the IM regulations.
Response
    PHMSA agrees with the NAPSR comment and has likewise found that
some operators do turn off inspection tools outside of HCAs. Therefore,
PHMSA is proposing to require that operators perform periodic
assessments of pipelines that are not already covered under the IM
program requirements in Sec.  195.452. Promulgation of such a
requirement will ensure that pipeline operators obtain the information
necessary for the prompt detection and remediation of corrosion and
other deformation anomalies (e.g., dents, gouges, and grooves) in all
locations, not just in areas that could affect HCAs.
Inclusion of Major Road and Railway Crossings as HCAs
    PHMSA requested comment on the need to include major road and
railway crossings as HCAs.
Comments
    Industry, three trade associations, three citizens' groups, one
regulatory association, one government/municipality, and one citizen
commented on this question.
    TransCanada Keystone, supported by the trade associations, API-
AOPL, TPA, TxOGA, and LMOGA, opposed including major roads and railway
crossings as HCAs. The commenters offered several reasons to support
that position (e.g., such a change would draw resources from other more
high risk areas, non-HCA areas are already assessed and remediated, and
there is no data to support such an action).
    Among the citizens' groups, PST stated that rail and major road
crossings should be included. TWS and AKW stated that all
transportation infrastructure, public lands, wetlands under the Clean
Water Act (CWA), cultural, historical, archeological and recreation
areas used for subsistence be included in HCAs.
    NAPSR also suggested that rail and major road crossings should be
included. NAPSR urged PHMSA to consider the effect of a release on
electric transmission facilities, gas pipelines, and railroads if major
road and rail crossings were not to be included in HCAs. NAPSR would
consider the effect of a release on electric transmission facilities,
gas pipelines, railroads, etc., and would treat major road and rail
crossings as HCAs for highly volatile liquids (HVLs) pipelines.
    The only government/municipality to comment on this question was
DLA. DLA indicated that these structures should be included in HCAs.
    Citizen Coyle commented that major roadways should be HCAs because
these areas could be affected by pipelines carrying HVLs that would
produce poisonous clouds if released.
Response
    PHMSA is not proposing to designate major road and railway
crossings as HCAs, but will consider whether the pipeline IM
requirements should be applied to these areas when completing the study
that Congress mandated under section 5 of the Pipeline Safety Act of
2011. PHMSA notes that the pipelines at such crossings would be
afforded additional protections under the other proposals made in this
proceeding, including the requirements for the performance of periodic
internal inspections and the use of leak detection systems.

C. Leak Detection Equipment and Emergency Flow Restricting Devices

    In the ANPRM, PHMSA asked for comment on whether to modify the
current requirements part 195 for leak detection equipment and
emergency flow restricting devices (EFRDs). Specifically, PHMSA asked
whether
     The use of leak detection equipment should be required for
hazardous liquid pipelines;
     The pipeline industry has developed any practices,
standards, or leak detection technologies that should be incorporated
by reference;
     Any industry practices or standards adequately address the
relevant safety considerations;
     State regulations for leak detection should be adopted by
regulation;
     Any new leak detection requirements should vary based on
the sensitivity of the affected areas;
     The pipeline industry has developed standards or practices
for the performance and location of EFRDs;
     The location of EFRDs should be specified by regulation;
and
     Additional research and development is needed to
demonstrate the suitability of any new leak detection technologies.
    As discussed below, PHMSA is considering requiring that all
hazardous liquid pipelines have a system for detecting leaks and expand
the use of EFRDs.
Expansion of Leak Detection Requirements
    In the ANPRM, PHMSA asked for comment on whether the agency should
expand the leak detection requirements.
Comments
    Industry and trade associations generally supported expansion of
the existing requirement in Sec.  195.452(i)(3) to most pipelines, but
opposed including more-specific requirements in the regulations. API-
AOPL, TxOGA, TransCanada Keystone, and LMOGA supported extending leak
detection requirements to all PHMSA-regulated pipelines, except for
rural gathering lines.
    Citizens' groups supported enhanced leak detection requirements.
TWS and PST opposed additional reliance on the current requirements in
Sec.  195.452(i)(3), stating that this regulation includes no
acceptance criteria and is virtually unenforceable. TWS further
supported expanding leak detection requirements to all pipelines under
PHMSA jurisdiction. NRDC indicated that leak detection requirements
should be expanded to include a requirement that

worst-case-discharge-pumping times be based on historical shutdown
times, rather than expected times. NRDC also said that operators should
immediately contact first responders at the first sign of an issue. One
citizen, Stec, suggested requiring use of ``smart coating'' with
embedded conductors that would break to indicate coating damage and
which could then trigger automatic response actions.
    The regulatory associations, DLA and MAWUC, supported expanded leak
detection requirements. MAWUC suggested PHMSA require the use of leak
detection equipment in all HCAs. DLA indicated that any new
requirements should be delayed until better technology is available.
    The government/municipality, NSB, recommended leak detection
requirements be expanded to all pipelines under PHMSA regulation. NSB
encouraged adoption of more stringent leak detection requirements for
sensitive offshore areas of the Beaufort and Chukchi seas.
Response
    As discussed earlier in this NPRM under the Background and
Proposals section, PHMSA will propose to expand the leak detection
requirements for HCA and non-HCA areas.
Consideration of New Industry Standards or Practices in Leak Detection
    PHMSA asked for public comment on whether any new industry
standards or practices should be considered for adoption in part 195.
Comments
    API-AOPL, TxOGA, LMOGA, and TransCanada Keystone all indicated that
the API-AOPL standard RP1165 (SCADA), RP 1167 (Pipeline Alarm
Management), and RP1168 (Control Room Management) are good standards to
utilize for leak detection systems. API-AOPL also pointed out that many
new technologies are being developed and existing methodologies are
continuously being improved for better leak detection capability;
however, many of these new technologies have not been proven in service
on cross-country pipelines.
    One citizens' group, NRDC, commented that new leak detection
standards should address the additional demands posed by hazardous
liquids. In particular, NRDC mentioned some hazardous liquids, such as
diluted bitumen, have multiphase properties that can cause false
alarms.
    The regulatory associations, NAPSR and DLA, both commented on new
industry standards and practices in leak detection. NAPSR mentioned the
new technology forward-looking infrared radar (FLIR) and encouraged
PHMSA to consider using such new technologies. NAPSR reported that FLIR
can detect changes in temperature near a pipeline from a winter leak,
even under snow, and that it can be used from aerial patrols.
    DLA indicated that any leak detection standards should be third-
party validated and listed by the National Work Group on Leak Detection
Evaluations (NWGLDE) and that leak detection in general for large
volume pipelines is not very effective at this time.
Response
    The commenters only offered three specific industry standards or
practices for consideration, and two of those standards, API RP1165
(SCADA) and RP1168 (Control Room Management), are already incorporated
into part 195 (see 49 CFR 195.3). PHMSA has concerns about the adequacy
and enforceability of the third standard, API RP 1167 (Pipeline Alarm
Management), and does not believe that it should be incorporated by
reference at this time.
    As previously discussed, PHMSA is proposing to require that
operators have a means for detecting leaks on all portions of a
hazardous liquid pipeline system. Consideration of FLIR and any other
emerging technologies would be required in evaluating what kinds of
leak detection systems are appropriate for a particular pipeline. PHMSA
will also be considering whether the use of specific leak detection
technologies should be required in preparing the Secretary's report to
Congress on that issue.
    PHMSA does not agree that third-party validation is a prerequisite
to issuing new leak detection requirements for hazardous liquid
pipelines. That limitation is not included in the Pipeline Safety Laws,
and PHMSA does not believe that such action is necessary as a matter of
administrative discretion.
Adequacy of Existing Industry Standards or Practices for Leak Detection
    PHMSA asked for public comment on whether any existing industry
standards or practices for leak detection are adequate for adoption
into part 195.
Comments
    TransCanada Keystone, TxOGA, LMOGA and API-AOPL submitted comments
indicating that the current leak detection evaluations performed as a
requirement of the IM program encompass many important factors for
proper leak detection. PHMSA should allow for the implementation of
recent regulatory changes, including the new Control Room Management
(CRM) rule, before making any changes. NAPSR commented that all
pipeline operators should, at a minimum, perform a tank balance
periodically to detect leakage.
    NSB recommended that PHMSA adopt improved leak detection system
standards and implement more stringent leak detection requirements for
the sensitive offshore areas of the Beaufort and Chukchi seas. NSB
stated that PHMSA should require: (1) Redundant leak detection systems
for offshore pipelines; (2) All offshore pipeline leak detection
systems to have the continuous capability to detect a daily discharge
equal to not more than 0.5% of daily throughput within 15 minutes, and
detect a pinhole leak within less than 24 hours; (3) All onshore
pipeline leak detection systems to have the continuous capability to
detect a daily discharge equal to not more than 1% of daily throughput
within 15 minutes, and detect a pinhole leak within less than 24 hours;
and (4) An initial performance test to verify leak detection accuracy
upon installation and at regular intervals thereafter.
Response
    PHMSA agrees that the factors listed in Sec.  195.452(i)(3) are an
appropriate basis for determining whether hazardous liquid pipelines
have an adequate leak detection system and is proposing to use those
factors as the basis for the requirements that would apply in all other
locations. However, a December 31, 2007, report that PHMSA prepared in
response to a mandate in the Pipeline Inspection, Protection,
Enforcement, and Safety Act (PIPES Act) of 2006 (Pub. L. 109-468),
confirmed that some operators had IM procedures that did not require
the performance of a leak detection evaluation, and others had adopted
an inadequate process for performing those evaluations. Operators are
reminded that any failure to comply with part 195, including the leak
detection requirements in Sec.  195.452(i)(3) and the proposed
modifications to Sec. Sec.  195.134 and 195.444, increases both the
likelihood and severity of pipeline accidents.
    PHMSA agrees that the new CRM requirements will improve the
detection and mitigation of leaks on hazardous liquid pipeline systems,
but does not agree that the implementation of improved leak detection
requirements should be delayed solely on account of the recent issuance
of those regulations. PHMSA will be monitoring the use of

leak detection systems by operators in complying with those
requirements in determining if additional safety standards are needed.
Consideration of State Requirements/Regulations for Leak Detection
    Some states have established leak detection requirements for
hazardous liquid pipeline systems. For example, the Alaska Department
of Environmental Conservation (ADEC) has promulgated a regulation (18
AAC 75.055) that states:
    (a) A crude oil transmission pipeline must be equipped with a leak
detection system capable of promptly detecting a leak, including
    (1) if technically feasible, the continuous capability to detect a
daily discharge equal to not more than one percent of daily throughput;
    (2) flow verification through an accounting method, at least once
every 24 hours; and
    (3) for a remote pipeline not otherwise directly accessible, weekly
aerial surveillance, unless precluded by safety or weather conditions.
    (b) The owner or operator of a crude oil transmission pipeline
shall ensure that the incoming flow of oil can be completely stopped
within one hour after detection of a discharge.
    (c) If above ground oil storage tanks are present at the crude oil
transmission pipeline facility, the owner or operator shall meet the
applicable requirements of 18 AAC 75.065, 18 AAC 75.066, and 18 AAC
75.075.
    (d) For facility oil piping connected to or associated with the
main crude oil transmission pipeline the owner or operator shall meet
the requirements of 18 AAC 75.080.
    Operators who install online leak detection systems can also
receive a reduction in the volume of crude oil that must be used in
complying with Alaska's oil spill response planning requirements (18
AAC 75.436(c)(3)).
    The State of Washington has also prescribed leak detection
requirements for hazardous liquid pipelines (WAC 480-75-300). Those
requirements, which are administered by the Washington Utilities and
Transportation Commission (WUTC), state:
    (1) Pipeline companies must rapidly locate leaks from their
pipeline. Pipeline companies must provide leak detection under flow and
no flow conditions.
    (2) Leak detection systems must be capable of detecting an eight
percent of maximum flow leak within fifteen minutes or less.
    (3) Pipeline companies must have a leak detection procedure and a
procedure for responding to alarms. The pipeline company must maintain
leak detection maintenance and alarm records.
Comments
    PHMSA received comments from several trade associations and one
citizens' group on state requirements for leak detection systems. API-
AOPL indicated that pipeline configuration and operational factors vary
by geographic location, and that other variability exists, including
fluid or product differences, batching, and other operational
conditions. Due to these factors, any type of prescriptive approach to
standards for leak detection is difficult to achieve and would be
better served using a performance standard. CRAC noted that multi-phase
lines are more susceptible to internal corrosion, and that state
regulations do not require IM or leak detection.
    NAPSR and DLA also commented. NAPSR encouraged PHMSA to allow the
states to set minimum leak detection criteria for intrastate pipelines.
DLA opposed development of criteria based on state requirements and
suggested that new requirements be third-party validated and listed by
NWGLDE.
Response
    PHMSA favors the use of performance-based safety standards and
believes that the regulations adopted by ADEC and WUTC show that
certain minimum threshold requirements can be established for leak
detection systems. PHMSA will be considering these and other similar
regulations in an evaluation of leak detection systems.
    With regard to NAPSR's comment, section 60104(c) of the Pipeline
Safety Laws allows states that have submitted a current certification
to adopt additional or more stringent safety standards for intrastate
hazardous liquid pipeline facilities, so long as those requirements are
compatible with the minimum federal safety standards. PHMSA has
prescribed mandatory leak detection requirements for hazardous liquid
pipelines that could affect HCAs and is proposing to make those
requirements applicable to all pipelines subject to part 195. States
that have submitted a current certification can establish additional or
more stringent leak detection standards for intrastate hazardous liquid
pipeline facilities, subject to the statutory compatibility
requirement.
    PHMSA does not agree that third-party validation is a prerequisite
to issuing new leak detection requirements for hazardous liquid
pipelines. That limitation is not included in the Pipeline Safety Laws,
and PHMSA does not believe that such action is necessary as a matter of
administrative discretion.
Different Leak Detection Requirements for Sensitive Areas
    Section 195.452(i)(3) contains a mandatory leak detection
requirement for hazardous liquid pipelines that could affect an HCA.
That regulation requires operators to consider several factors (i.e.,
the length and size of the pipeline, type of product carried, proximity
to the HCA, the swiftness of leak detection, location of nearest
response personnel, leak history, and risk assessment results) in
selecting an appropriate leak detection system.
Comments
    PHMSA received many comments in response to whether there should be
different leak detection requirements for sensitive areas. The trade
associations, TxOGA and LMOGA, supported API-AOPL's comments that most
leak detection methods cannot target specific areas. API-AOPL further
stated that leak detection for sensitive areas can be achieved through
comprehensive risk-based evaluation, but that external monitoring is
too invasive and is not yet proven or cost effective.
    The regulatory associations, government/municipalities, and
citizens all supported increased leak detection requirements for
sensitive areas. The regulatory association, NAPSR, mentioned the use
of FLIR for sensitive areas and stated that special actions beyond
patrols should be required for sensitive areas. DLA indicated leak
detection standards should be third-party validated. MAWUC and a
citizen, Coyle, recommended requiring external leak detectors in HCAs.
Coyle would also require external leak detectors for above-ground
pipelines transporting highly volatile liquids. NSB encouraged PHMSA to
adopt improved leak detection standards and implement more stringent
requirements for sensitive areas.
Response
    PHMSA believes that the leak detection requirements in Sec.
195.452(i)(3) can provide adequate protection for sensitive areas and
is proposing to use those requirements as the basis for establishing
requirements that would apply to hazardous liquid pipelines in all
other locations. Under the current and proposed regulations, operators
are required to consider several factors in selecting an appropriate
leak detection system, including the characteristics and history of the
affected pipeline, the capabilities of the available leak

detection systems, and the location of emergency response personnel.
PHMSA commissioned Kiefner and Associates, Inc., to perform a study on
leak detection systems used by hazardous liquid operators. That study,
titled ``Leak Detection Study,'' \4\ was completed on December 10,
2012, and was submitted to Congress on December 27, 2012. PHMSA is
considering, in a different rulemaking activity, whether to adopt
additional or more stringent requirements for sensitive areas in
response to this study.
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Key Issues for New Leak Detection Standards
Comments
    The trade associations, TxOGA, LMOGA, and API-AOPL, supported by an
industry commenter, TransCanada Keystone, stated that PHMSA should
identify issues that might adversely affect response times, including
limiting the consequences for first responder deployment and allowing
for the withdrawal of erroneous leak notifications. NAPSR, the only
regulatory association to comment, found that any new standards should
consider detection of small leaks in HCAs, maintenance, accuracy,
transient conditions, system capabilities, and alarm management.
    Three government/municipalities commented on this issue. DLA stated
that any standards should address sensitivity, probability of false
alarms, minimum leak detection capabilities, frequency, and be based on
leak detection technology. MAWUC supported more stringent reporting and
repair requirements. NSB indicated that PHMSA should require redundant
leak detection systems for offshore lines. NSB also indicated the
technology available for leak detection systems is vastly improved and
industry should bear the burden to utilize these systems.
Response
    The Pipeline Safety Laws contain a number of general factors that
must be considered in prescribing new safety standards, including the
reasonableness of the standard, the estimated benefits and costs, and
the views and recommendations of the Technical Hazardous Liquid
Pipeline Safety Standards Committee (49 U.S.C. 60102(b)). The Pipeline
Safety Laws also contain specific factors that must be considered in
prescribing certain safety standards, such as for smart pigs (49 U.S.C.
60102(f)) or low-stress hazardous liquid pipelines (49 U.S.C.
60102(k)).
    In the case of leak detection, Congress has enacted prior statutory
mandates that required the Secretary to survey and assess the need for
additional safety standards. PHMSA and its predecessor agency, RSPA,
complied with those mandates by producing two reports and promulgating
additional safety standards for leak detection systems. Congress
enacted a similar provision in section 8 of the Pipeline Safety Act of
2011, including a requirement that the Secretary submit a report to
Congress that provides an analysis of the technical limitations of
current leak detection systems and the practicability, safety benefits,
and adverse consequence of establishing additional standards for the
use of such systems.
    The commenters identified several issues that should be considered
in establishing new leak detection standards, including the need to
minimize false alarms, to set appropriate volumetric thresholds, and to
encourage the use of best available technologies.
Statistical Analyses of Leak Detection Requirements
    PHMSA asked the public to comment on the availability of statistics
on whether existing practices or standards on leak detection have
contributed to reduced spill volumes and consequences.
Comments
    One response submitted by API-AOPL, supported by TransCanada
Keystone, LMOGA, and TxOGA, stated that the association was unaware of
any recent statistics in regard to this topic. API-AOPL further