including specific timing provisions relating to the identification of
ruptures. Specifically, operators must have procedures in place
allowing them to identify a rupture event within 10 minutes of the
initial notification to the operator. PHMSA also proposes to require
that operators maintain liaison with and contact the appropriate public
safety answering point (9-1-1 emergency call center) in the event an
operator's pipeline ruptures.

Sec. 192.617 Investigation of Failures and Incidents

    PHMSA proposes to revise Sec.  192.617 to define the elements that
an operator must incorporate when conducting a post-incident analysis
of certain specifically defined incidents, namely ruptures, and other
release and failure events involving the activation of rupture-
mitigation valves.
    The proposed revision would require the operator to identify
potential preventive and mitigative measures that could be taken to
reduce or limit the release volume and damage from similar events in
the future. The post-incident review would address factors associated
with this rulemaking, including but not limited to detection and
mitigation actions, response time, valve location, valve actuation, and
SCADA performance. Upon completing the post-accident analysis, the
operator must develop and implement the lessons learned throughout its
suite of procedures, including in pertinent operator personnel training
and qualification programs, and in design, construction, testing,
maintenance, operations, and emergency procedure manuals and
specifications.

Sec. 192.634 Transmission Lines: Onshore Valve Shut-Off for Rupture
Mitigation

    Proposed new Sec.  192.634 would establish an emergency operations
standard requiring operators to isolate certain ruptured pipeline
segments as soon as practicable via rupture-mitigation valves with
complete segment isolation as soon as practicable but within 40 minutes
of identifying a rupture. This would apply to newly constructed and
entirely replaced onshore gas transmission pipeline segments in HCAs
and Class 3 and Class 4 locations with nominal diameters greater than
or equal to 6 inches, and it would also apply to any gas transmission
pipelines where 2 or more contiguous miles of pipeline with nominal
diameters greater than or equal to 6 inches are replaced in HCAs and
Class 3 and Class 4 locations. This NPRM would require that operators
designate shut-off segments in these areas and designate mainline
valves used to isolate ruptures on those shutoff segments as rupture-
mitigation valves. This rulemaking would establish maximum distances
between rupture-mitigation valves from 8 to 20 miles depending on the
pipeline's class location. Compliance with the standard could be
achieved using ASVs, RCVs, or an equivalent technology. Operators may
install manually or locally operated valves to act as rupture-
mitigation valves only if the installation of ASVs, RCVs, or equivalent
technology is not feasible at the location, provided the operator
demonstrates that the 40-minute closure standard can be achieved under
emergency conditions. Operators using manual valves or other equivalent
technology must notify PHMSA in accordance with the procedure outlined
in Sec.  192.634(h). The NPRM would also require that operators monitor
the position and operational status of all rupture-mitigation valves.
Operators will be required to meet these provisions within 12 months
after the effective date of the final rule.

Sec. 192.745 Valve Maintenance: Transmission Lines

    PHMSA proposes to revise Sec.  192.745 by adding paragraphs (c),
(d), and (e) to incorporate the maintenance, inspection, and operator
drills required to ensure operators can close a rupture-mitigation
valve as soon as practicable, but within 40 minutes of rupture
identification. Demonstration and verification requirements are
proposed, including point-to-point verification tests for rupture-
mitigation valves that are ASVs or RCVs and initial validation drills
and periodic confirmation drills for any manually or locally operated
valve identified as a rupture-mitigation valve. The operator would be
required to identify corrective actions and lessons learned resulting
from its validation and confirmation drills and share and implement
them across its entire network of pipeline systems.

Sec. 192.935 What additional preventive and mitigative measure must an
operator take?

    PHMSA proposes to revise Sec.  192.935(c) to clarify the
requirements for conducting ASV and RCV evaluations for HCAs,
particularly when RCVs and ASVs are installed as preventive and
mitigative measures associated with improved response times for
pipeline ruptures. The amendments would require that operators be able
to evaluate and demonstrate that they could identify a rupture within
10 minutes in accordance with the proposed Sec.  192.615(a)(6) and meet
the standard specified in the proposed Sec.  192.634 to isolate shut-
off segments in HCAs during rupture events as soon as practicable but
within 40 minutes. Operators would also be required to demonstrate,
through the risk analysis required by this section, that any ASVs

or RCVs installed under this section can comply with the proposed valve
maintenance requirements at Sec.  192.745.

V. Section-by-Section Analysis for Changes to 49 CFR Part 195 for
Hazardous Liquid Pipelines

Sec. 195.2 Definitions

    Most of the requirements of the NPRM would be triggered by the
identification of a ``rupture.'' Section 195.2 would be amended to
define ``rupture'' for hazardous liquid pipelines as any of the
following events that involve an uncontrolled release of a large volume
of hazardous liquid over a short period of time: (1) An unanticipated
or unplanned flow rate change of 10 percent or greater or a pressure
loss of 10 percent or greater, occurring within a time interval of 15
minutes or less, unless the operator has documented in advance of the
flow rate change or pressure loss the need for a higher flow rate
change or higher pressure-change threshold due to pipeline flow
dynamics and terrain elevation changes that cause fluctuations in
hazardous liquid flow that are typically higher than a flow rate change
or pressure loss of 10 percent or greater in a time interval of 15
minutes or less; (2) An unexpected flow rate change, pressure change,
instrumentation indication, or equipment function that may be
representative of an event defined above; or (3) An apparent large-
volume, uncontrolled release of hazardous liquid or a failure observed
by operator personnel, the public, or public authorities, that is
reported to the operator and that may be representative of an
unintentional and uncontrolled release event that is defined above.

Sec. 195.258 Valves: General

    PHMSA proposes to require that all valves on newly constructed and
entirely replaced hazardous liquid lines that have nominal diameters
greater than or equal to 6 inches be RCVs, ASVs, or an equivalent
technology, unless such valves are not economically, technologically,
or operationally feasible. PHMSA proposes to permit operators install
manually or locally operated valves only when there are feasibility
issues precluding the installation of ASVs, RCVs, or equivalent
technology. All valves installed under this requirement would have to
meet the new rupture-mitigation standards proposed in Sec.  195.418 and
isolate a ruptured pipeline segment as soon as practicable, but within
40 minutes of rupture identification. Rupture identification would be
defined in Sec.  195.2 to occur when a rupture is reported to or
observed by pipeline operating personnel or a controller.

Sec. 195.260 Valves: Location

    Section 195.260 proposes the requirements for the location of
valves on newly constructed hazardous liquid pipelines, entirely
replaced hazardous liquid pipelines, and hazardous liquid pipelines
where 2 or more contiguous miles have been replaced. PHMSA proposes to
revise Sec.  195.260 to incorporate new maximum valve spacing
requirements for the general placement of valves, including a 20-mile
maximum spacing requirement for valves on pipelines that could not
affect high consequence areas, with more stringent maximum spacing
requirements of 15 miles and 7.5 miles for pipelines that could affect
HCAs and HVL pipelines in populated areas, respectively. These valve
spacing requirements carry over to the rupture-mitigation valve spacing
requirements at Sec.  195.418 as well, where operators would be
required to install rupture-mitigation valves at a maximum of every 15
miles but no further than 7\1/2\ miles from the HCA segment endpoints
and at a maximum of every 7\1/2\ miles for HVL lines in highly
populated areas. Revisions to Sec.  195.260 would also include two
miscellaneous clarifications: (1) To explicitly include carbon dioxide
as a transported commodity whose consequences are to be considered, and
(2) to include new requirements pertaining to valves at water crossings
to ensure these valves will not be impacted by flood conditions and to
allow multiple water crossings to be protected by a single pair of
valves.

Sec. 195.402 Procedural Manual for Operations, Maintenance, and
Emergencies

    PHMSA proposes to revise Sec.  195.402 to identify the areas
requiring an immediate response by the operator to prevent hazards to
the public, property, or the environment if the facilities failed or
malfunctioned, including segments that could affect HCAs and segments
with valves that are specified in Sec. Sec.  195.418 and 195.452(i)(4).
    PHMSA is also revising Sec.  195.402 to define the elements that an
operator must incorporate when conducting a post-accident analysis of
ruptures and other release and failure events involving the activation
of rupture-mitigation valves. The proposed revision would require the
operator to identify potential preventative and mitigative measures
that could be taken to reduce or limit the release volume and damage
from similar events in the future. The post-accident review would
address factors associated with this rulemaking, including but not
limited to detection and mitigation actions, response time, valve
location, valve actuation, and SCADA performance. Upon completion of
this post-accident analysis, the operator would be required to develop
and implement the lessons learned throughout its suite of procedures,
including in pertinent operator personnel training and qualification
programs, and in design, construction, testing, maintenance,
operations, and emergency procedure manuals and specifications.
    Further, PHMSA is revising Sec.  195.402 to clarify that
requirements to establish liaison with emergency officials must include
public safety answering points (9-1-1 emergency call centers) and that
requirements for notifying emergency officials when events occur must
include notifications to those local public safety answering points.
    Section 195.402 also require that emergency procedures provide for
rupture detection and valve closure in response to a leakage or failure
event, including specific timing provisions relating to ruptures.
Specifically, operators must have procedures in place so that they can
identify a rupture event within 10 minutes of the initial notification
to the operator. This section would also be revised as a matter of
minor clarification to incorporate valve shut-off as an example of an
emergency action to minimize the hazards of released hazardous liquid
or carbon dioxide to life, property, or the environment.

Sec. 195.418 Valves: Onshore Valve Shut-Off for Rupture Mitigation

    Proposed new Sec.  195.418 would establish an emergency operations
standard requiring operators to isolate certain ruptured pipeline
segments as soon as practicable via rupture-mitigation valves with
complete segment isolation within 40 minutes of identifying a rupture.
This standard would apply to newly constructed and entirely replaced
onshore hazardous liquid pipelines in HCAs and that could affect HCAs
with nominal diameters greater than or equal to 6 inches, and it would
also apply to any hazardous liquid pipelines where 2 or more contiguous
miles of pipeline with nominal diameters greater than or equal to 6
inches are replaced in HCAs or where they could affect HCAs. This NPRM
would require that operators designate shut-off segments in these areas
and designate mainline valves used to isolate ruptures on those shut-
off segments as rupture-mitigation

valves. This NPRM would establish maximum distances of 15 miles between
rupture-mitigation valves and 7\1/2\ miles between rupture-mitigation
valves on HVL lines, which are consistent with the proposed spacing
requirements of Sec.  195.260. Operators could use ASVs, RCVs, an
equivalent technology, or manually operated valves (if the operator
demonstrates infeasibility of ASVs, RCVs and equivalent technology,
that the standard can be achieved under emergency conditions, and
provides notification to PHMSA). Operators would also be required to
monitor the position and operational status of all rupture-mitigation
valves. Operators will be required to meet these provisions within 12
months after the effective date of the final rule.

Sec. 195.420 Valve Maintenance

    PHMSA proposes to revise Sec.  195.420 to incorporate the
maintenance, inspection, and operator drills required to ensure
operators can close a rupture-mitigation valve as soon as practicable
but within 40 minutes. Demonstration and verification requirements are
proposed, including point-to-point verification tests for rupture-
mitigation valves that are ASVs or RCVs and initial validation drills
and periodic confirmation drills for any manually or locally operated
valves identified as rupture-mitigation valves. This section would also
require an operator to identify corrective actions and lessons learned
resulting from its validation or confirmation drills and share and
implement those lessons learned across its entire network of pipeline
systems.

Sec. 195.452 Pipeline Integrity Management in High Consequence Areas

    PHMSA proposes to revise Sec.  195.452(i)(4) to clarify the
existing requirements for the conduct of EFRD evaluations for HCAs,
particularly when operators use EFRDs as rupture-mitigation valves on
applicable lines. Further, the amendments would also require that
operators be able to evaluate and demonstrate that they could identify
a rupture within 10 minutes in accordance with the proposed Sec.
195.402 and meet the standard specified in the proposed Sec.  195.418
to isolate shut-off segments that could affect HCAs during rupture
events, and the amendments would require that any EFRDs installed on
shut-off segments also comply with the design, operation, testing, and
maintenance requirements of Sec. Sec.  195.258, 195.260, 195.402, and
195.420.

VI. Regulatory Analyses and Notices

A. Statutory/Legal Authority for This Rulemaking

    This NPRM is published under the authority of the Federal Pipeline
Safety Law (49 U.S.C. 60101 et seq.). Section 60102 authorizes the
Secretary of Transportation to issue regulations governing the design,
installation, inspection, emergency procedures, testing, construction,
extension, operation, replacement, and maintenance of pipeline
facilities. The Secretary delegated this authority to PHMSA at 49 CFR
1.97(a).

B. Executive Orders 12866 and 13771, and DOT Regulatory Policies and
Procedures

    Executive Order 12866 requires agencies to regulate in the ``most
cost-effective manner,'' to make a ``reasoned determination that the
benefits of the intended regulation justify its costs,'' and to develop
regulations that ``impose the least burden on society.'' This NPRM has
been determined to be significant under Executive Order 12866 and the
Department of Transportation's Regulatory Policies and Procedures. This
NPRM has been reviewed by the Office of Management and Budget in
accordance with Executive Order 12866 (Regulatory Planning and Review)
and is consistent with the Executive Order 12866 requirements and 49
U.S.C. 60102(b)(5)-(6).
    Consistent with Executive Order 12866, PHMSA has prepared a
preliminary assessment of the benefits and costs of the proposed rule
as well as reasonable alternatives. PHMSA anticipates that, if
promulgated, this NPRM will provide benefits to the public through more
rapid valve closure resulting in better consequence mitigation.
    For hazardous liquid pipelines, most damages are calculated by the
cost of cleanup and long-term environmental remediation.\39\ Therefore,
a reduction in the amount of product released from a hazardous liquid
pipeline can directly correlate to a reduction in damages. As discussed
earlier in this NPRM, in the Enbridge incident near Marshall, MI, the
pipeline continued to pump oil for 18 hours before valves were closed,
resulting in approximately 20,000 barrels of oil being released. With
faster rupture detection, pump shutdowns, and valve closures in line
with this NPRM, the pipeline would have been isolated 17 hours and 20
minutes earlier, which would have resulted in a substantially lower
spill size, environmental impact, and remedial costs.
---------------------------------------------------------------------------

    \39\ PHMSA notes that HVL releases may have similar incident
profiles to natural gas transmission pipelines, as escaping product
can be ignited and cause similar damage via a rupture.
---------------------------------------------------------------------------

    Natural gas transmission pipeline incidents result predominately in
fatalities, injuries, or property damages that are not linearly related
to the quantity of natural gas released. For small incidents and for
those incidents in remote locations, damages may be limited to pipeline
repair and gas loss costs. Larger incidents, on the other hand, likely
involve the ignition of gas and extensive property damage and personal
injury, depending on the location of the release and its proximity to
buildings, homes, or other areas. A reduction in the cumulative product
release over these types of incidents would not necessarily imply
avoided damages in the way that it would apply to hazardous liquid
pipelines as discussed above. For example, in the PG&E incident, the
homes destroyed by the initial rupture would not have been saved
through a more prompt valve closure. However, as discussed earlier in
this document, during the 95 minutes it took PG&E to isolate the
ruptured segment, the fire resulting from the rupture was being fed by
the transmission line, and firefighters could not start firefighting
and containment activities until the line was isolated. Earlier valve
closure, in that circumstance, could have limited the spread of fire
and additional damage beyond the immediate rupture area.
    PHMSA estimates that the NPRM will result in annualized costs of
approximately $3.1 million per year, calculated at a 7 percent discount
rate. The table below presents the annualized costs for the baseline
and this NPRM, at a 3 percent and a 7 percent discount rate:

             Table 1--Annualized Costs of the Proposed Rule
                            [Millions 2015$]
------------------------------------------------------------------------
                                                        7%         3%
                    System type                      Discount   Discount
                                                       rate       rate
------------------------------------------------------------------------
Gas transmission..................................       $1.2       $1.0
Hazardous liquid..................................        1.9        1.5
                                                   ---------------------
Total.............................................        3.1        2.5
------------------------------------------------------------------------

    The NPRM is expected to be an E.O. 13771 regulatory action. Details
on the estimated costs of this NPRM can be found in the rule's economic
analysis.
    For more information, please see the PRIA in the docket for this
rulemaking.

C. Executive Order 13132: Federalism

    PHMSA has analyzed this rulemaking action according to Executive
Order 13132 (``Federalism''). While this NPRM may preempt some State
requirements, it does not impose any regulation that has substantial
direct effects on the States, the relationship between the national
government and the States, or the distribution of power and
responsibilities among the various levels of government. Therefore, the
consultation and funding requirements of Executive Order 13132 do not
apply. The pipeline safety laws, specifically 49 U.S.C. 60104(c),
prohibit State safety regulation of interstate pipelines. Under the
pipeline safety laws, States have the ability to augment pipeline
safety requirements for intrastate pipelines, but may not approve
safety requirements less stringent than those required by Federal law.
A State may also regulate an intrastate pipeline facility PHMSA does
not regulate.

D. Regulatory Flexibility Act

    The Regulatory Flexibility Act, as amended by the Small Business
Regulatory Flexibility Fairness Act of 1996, requires Federal
regulatory agencies to prepare an Initial Regulatory Flexibility
Analysis (IRFA) for any proposed rule subject to notice-and-comment
rulemaking under the Administrative Procedure Act unless the agency
head certifies that the rulemaking will not have a significant economic
impact on a substantial number of small entities.
    PHMSA prepared an IRFA of the potential economic impact on small
entities, which is available in the docket for this NPRM. For a worst-
case scenario, PHMSA compared compliance costs to estimated sales for
businesses. Average annualized costs could exceed 1 percent of sales
for 34 (8 percent) of the estimated small gas transmission entities and
12 (19 percent) of the estimated small hazardous liquid operators for a
total of 46 (10 percent) entities combined across both sectors. Average
annualized costs could exceed 3% of sales for 3 (1 percent) gas
transmission operators and 4 (6 percent) hazardous liquid operators,
which represent 7 (1 percent) of the total estimated small business
entities.
    Due to various uncertainties in the screening analysis (see Table 7
in the IRFA), PHMSA seeks comments regarding the impacts of the NPRM on
small entities. PHMSA will subsequently modify the IRFA and make a
determination as to whether this NPRM will have a significant economic
impact on a number of small entities at the final rule stage.

E. National Environmental Policy Act

    PHMSA analyzed this NPRM in accordance with section 102(2)(c) of
the National Environmental Policy Act (42 U.S.C. 4332), the Council on
Environmental Quality regulations (40 CFR parts 1500-1508), and DOT
Order 5610.1C, and has preliminarily determined this action will not
significantly affect the quality of the human environment. The
Environmental Assessment for this NPRM is in the docket.

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

    PHMSA has analyzed this NPRM in accordance with the principles and
criteria contained in Executive Order 13175 (``Consultation and
Coordination with Indian Tribal Governments''). Because this NPRM is
not expected to have Tribal implications and is not expected to impose
substantial direct compliance costs on Indian Tribal governments, PHMSA
does not anticipate that the funding and consultation requirements of
Executive Order 13175 will apply. PHMSA seeks comment on the
applicability of the executive order to this NPRM.

G. Executive Order 13211

    This NPRM is not anticipated to be a ``significant energy action''
under Executive Order 13211 (Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use). It is not
likely to have a significant adverse effect on supply, distribution, or
energy use. Further, the Office of Information and Regulatory Affairs
has not designated this proposed rule as a significant energy action.

H. Paperwork Reduction Act

    Pursuant to 5 CFR 1320.8(d), PHMSA is required to provide
interested members of the public and affected agencies with an
opportunity to comment on information collection and recordkeeping
requests. PHMSA estimates that the proposals in this NPRM will create
the following Paperwork Reduction Act impacts:
    PHMSA proposes to create a new information collection to cover the
recordkeeping requirement for post-incident recordkeeping called:
``Rupture/Shut-off Valve: Post-Incident Records for Pipeline
Operators.'' PHMSA also proposes to create a new information collection
called ``Alternative Technology for Onshore Rupture Mitigation
Notifications'' to cover this specific notification requirement.
    PHMSA will submit information collection requests to the Office of
Management and Budget (OMB) for approval based on the requirements that
trigger components of the Paperwork Reduction Act in this NPRM. PHMSA
will also request two new OMB Control Numbers for these collections.
These information collections are contained in the pipeline safety
regulations, 49 CFR parts 190-199. The following information is
provided for each of these information collections: (1) Title of the
information collection; (2) OMB control number; (3) Current expiration
date; (4) Type of request; (5) Abstract of the information collection
activity; (6) Description of affected public; (7) Estimate of total
annual reporting and recordkeeping burden; and (8) Frequency of
collection. The information collection burdens are estimated as
follows:
    1. Title: ``Rupture/Valve Shut-off: Post-Incident Records for
Pipeline Operators.''
    OMB Control Number: Will request one from OMB.
    Current Expiration Date: New Collection--To be determined.
    Abstract: This NPRM proposes to amend 49 CFR 192.617 and 195.402 to
require operators who have experienced a rupture or rupture-mitigation
valve shut-off to complete a post-incident summary. The post-incident
summary, all investigation and analysis documents used to prepare it,
and records of lessons learned must be kept for the life of the
pipeline. PHMSA estimates this recordkeeping requirement will result in
50 responses annually and has allotted each respondent 8 hours per
response to make and maintain the required records. PHMSA does not
currently have an information collection that covers this requirement
and will request the approval of this new collection, along with a new
OMB Control Number, from the Office of Management and Budget.
    Affected Public: Operators of PHMSA-regulated pipelines.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 50.
    Total Annual Burden Hours: 400.
    Frequency of Collection: On occasion.

    2. Title: ``Alternative Equivalent Technology for Onshore Rupture
Mitigation Notifications.''
    OMB Control Number: Will request one from OMB.
    Current Expiration Date: New Collection--To be determined.

    Abstract: This NPRM proposes a new paragraph (d) in both 49 CFR
192.634 and 195.418 requiring operators who elect to use alternative
equivalent technology to notify, in accordance with 192.949, the Office
of Pipeline Safety at least 90 days in advance of use. An operator
choosing this option must include a technical and safety evaluation,
including design, construction, and operating procedures for the
alternative equivalent technology to the Associate Administrator of
Pipeline Safety with the notification. PHMSA would then have 90 days to
object to the alternative equivalent technology via letter from the
Associate Administrator of Pipeline Safety; otherwise, the alternative
equivalent technology would be acceptable for use. PHMSA estimates this
notification requirement will result in 2 responses annually and has
allotted each respondent 40 hours per response to conduct this task.
PHMSA does not currently have an information collection that covers
this requirement and will request the approval of this new collection,
along with a new OMB Control Number, from the Office of Management and
Budget.
    Affected Public: Operators of PHMSA-regulated pipelines.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 2.
    Total Annual Burden Hours: 80.
    Frequency of Collection: On occasion.

    Requests for copies of these information collections should be
directed to Angela Hill, Office of Pipeline Safety (PHP-30), Pipeline
and Hazardous Materials Safety Administration, 2nd Floor, 1200 New
Jersey Avenue SE, Washington, DC 20590-0001, Telephone:<PHONE_NUMBER>.
    Comments are invited on:
    (a) The need for the proposed collection of information for the
proper performance of the functions of the agency, including whether
the information will have practical utility;
    (b) The accuracy of the agency's estimate of the burden of the
revised collection of information, including the validity of the
methodology and assumptions used;
    (c) Ways to enhance the quality, utility, and clarity of the
information to be collected; and
    (d) Ways to minimize the burden of the collection of information on
those who are to respond, including the use of appropriate automated,
electronic, mechanical, or other technological collection techniques.
    (e) Ways the collection of this information is beneficial or not
beneficial to public safety.
    Send comments directly to the Office of Management and Budget,
Office of Information and Regulatory Affairs, Attn: Desk Officer for
the Department of Transportation, 725 17th Street NW, Washington, DC
20503. Comments should be submitted on or prior to April 6, 2020.

I. Unfunded Mandates Reform Act of 1995

    The analysis PHMSA performed in accordance with preparing the
Preliminary Regulatory Impact Assessment does not expect this NPRM to
impose unfunded mandates per the Unfunded Mandates Reform Act of 1995.
It is not expected to result in costs of $100 million, adjusted for
inflation, or more in any one (1) year to either State, local, or
tribal governments, in the aggregate, or to the private sector, and is
the least burdensome alternative that achieves the objective of the
proposed rulemaking. A copy of the Preliminary Regulatory Impact
Assessment is available for review in the docket.

J. Privacy Act Statement

    Anyone may search the electronic form of all comments received for
any of our dockets. You may review DOT's complete Privacy Act
Statement, published on April 11, 2000 (65 FR 19476), in the Federal
Register at: https://www.govinfo.gov/content/FR-2000-04-11/pdf/00-8505.pdf.

K. Regulation Identifier Number

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

List of Subjects

49 CFR Part 192

    Gas, Incorporation by reference, Natural gas, Pipeline safety,
Reporting and recordkeeping requirements.

49 CFR Part 195

    Anhydrous ammonia, Carbon dioxide, Incorporation by reference,
Petroleum, Pipeline safety, Reporting and recordkeeping requirements.

    In consideration of the foregoing, PHMSA proposes to amend 49 CFR
parts 192 and 195 as follows:

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

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

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

0
2. In Sec.  192.3, the definition of ``rupture'' is added in
alphabetical order to read as follows:

Sec.  192.3   Definitions.

* * * * *
    Rupture means any of the following events that involve an
uncontrolled release of a large volume of gas:
    (1) A release of gas observed or reported to the operator by its
field personnel, nearby pipeline or utility personnel, the public,
local responders, or public authorities, and that may be representative
of an unintentional and uncontrolled release event defined in
paragraphs (2) or (3) of this definition;
    (2) An unanticipated or unplanned pressure loss of 10 percent or
greater, occurring within a time interval of 15 minutes or less, unless
the operator has documented in advance of the pressure loss the need
for a higher pressure-change threshold due to pipeline flow dynamics
that cause fluctuations in gas demand that are typically higher than a
pressure loss of 10 percent in a time interval of 15 minutes or less;
or
    (3) An unexplained flow rate change, pressure change,
instrumentation indication, or equipment function that may be
representative of an event defined in paragraph (2) of this definition.
    Note: Rupture identification occurs when a rupture, as defined in
this section, is first observed by or reported to pipeline operating
personnel or a controller.
* * * * *
0
3. In Sec.  192.179, paragraph (e) is added to read as follows:

Sec.  192.179   Transmission line valves.

* * * * *
    (e) All onshore transmission line segments with diameters greater
than or equal to 6 inches that are constructed or entirely replaced
after [DATE 12 MONTHS AFTER EFFECTIVE DATE OF FINAL RULE] must have
automatic shutoff valves, remote-control valves, or equivalent
technology installed at intervals meeting the appropriate valve spacing
requirements of this section. An operator may only install a manual
valve under this paragraph if it can demonstrate to PHMSA that
installing an automatic shutoff valve, remote-

control valve, or equivalent technology would be economically,
technically, or operationally infeasible. An operator using alternative
equivalent technology or manual valve must notify PHMSA in accordance
with the procedure in Sec.  192.634(h). All valves and technology
installed under this paragraph must meet the requirements of Sec.
192.634(c), (d), (f), and (g).
0
4. Section 192.610 is added to read as follows:

Sec.  192.610   Change in class location: Change in valve spacing.

    If a class location change on a transmission line occurs after
[EFFECTIVE DATE OF FINAL RULE] and results in pipe replacement to meet
the maximum allowable operating pressure requirements in Sec. Sec.
192.611, 192.619, or 192.620, then the requirements in Sec. Sec.
192.179 and 192.634 apply to the new class location, and the operator
must install valves as necessary to comply with those sections. Such
valves must be installed within 24 months of the class location change
in accordance with Sec.  192.611(d).
0
5. In Sec.  192.615, paragraphs (a)(2), (6), (8), and (11), and
paragraph (c) introductory text are revised to read as follows:

Sec.  192.615   Emergency plans.

    (a) * * *
    (2) Establishing and maintaining adequate means of communication
with the appropriate public safety answering point (9-1-1 emergency
call center), as well as fire, police, and other public officials, to
learn the responsibility, resources, jurisdictional area, and emergency
contact telephone numbers for both local and out-of-area calls of each
government organization that may respond to a pipeline emergency, and
to inform the officials about the operator's ability to respond to the
pipeline emergency and means of communication.
* * * * *
    (6) Taking necessary actions, including but not limited to,
emergency shutdown, valve shut-off, and pressure reduction, in any
section of the operator's pipeline system to minimize hazards of
released gas to life, property, or the environment. Each operator
installing valves in accordance with Sec.  192.179(e) or subject to the
requirements in Sec.  192.634 must also evaluate and identify a rupture
as defined in Sec.  192.3 as being an actual rupture event or non-
rupture event in accordance with operating procedures as soon as
practicable but within 10 minutes of the initial notification to or by
the operator, regardless of how the rupture is initially detected or
observed.
* * * * *
    (8) Notifying the appropriate public safety answering point (9-1-1
emergency call center), as well as fire, police, and other public
officials, of gas pipeline emergencies to coordinate and share
information to determine the location of the release, including both
planned responses and actual responses during an emergency. The
operator (pipeline controller or the appropriate operator emergency
response coordinator) must immediately and directly notify the
appropriate public safety answering point (9-1-1 emergency call center)
or other coordinating agency for the communities and jurisdictions in
which the pipeline is located after the operator determines a rupture
has occurred when a release is indicated and rupture-mitigation valve
closure is implemented.
* * * * *
    (11) Actions required to be taken by a controller during an
emergency in accordance with the operator's emergency plans and
Sec. Sec.  192.631 and 192.634.
* * * * *
    (c) Each operator must establish and maintain liaison with the
appropriate public safety answering point (9-1-1 emergency call
center), as well as fire, police, and other public officials to:
* * * * *
0
6. Section 192.617 is revised to read as follows:

Sec.  192.617   Investigation of failures and incidents.

    (a) Post-incident procedures. Each operator must establish and
follow post-incident procedures for investigating and analyzing
failures and incidents as defined in Sec.  191.3, including sending the
failed pipe, component, or equipment for laboratory testing or
examination, where appropriate, to determine the causes and
contributing factors of the failure or incident and minimize the
possibility of a recurrence.
    (b) Post-incident lessons learned. Each operator must develop,
implement, and incorporate lessons learned from a post-incident review
into its procedures, including in pertinent operator personnel training
and qualification programs, and in design, construction, testing,
maintenance, operations, and emergency procedure manuals and
specifications.
    (c) Analysis of rupture and valve shut-offs; preventive and
mitigative measures. If a failure or incident involves a rupture as
defined in Sec.  192.3 or the closure of a rupture-mitigation valve as
defined in Sec.  192.634, the operator must also conduct a post-
incident analysis of all factors impacting the release volume and the
consequences of the release, and identify and implement preventive and
mitigative measures to reduce or limit the release volume and damage in
a future failure or incident. The analysis must include all relevant
factors impacting the release volume and consequences, including, but
not limited to, the following:
    (1) Detection, identification, operational response, system shut-
off, and emergency response communications, based on the type and
volume of the release or failure event;
    (2) Appropriateness and effectiveness of procedures and pipeline
systems, including SCADA, communications, valve shut-off, and operator
personnel;
    (3) Actual response time from rupture detection to initiation of
mitigative actions, and the appropriateness and effectiveness of the
mitigative actions taken;
    (4) Location and the timeliness of actuation of rupture-mitigation
valves identified under Sec.  192.634; and
    (5) All other factors the operator deems appropriate.
    (d) Rupture post-incident summary. If a failure or incident
involves a rupture as defined in Sec.  192.3 or the closure of a
rupture-mitigation valve as defined in Sec.  192.634, the operator must
complete a summary of the post-incident review required by paragraph
(c) of this section within 90 days of the failure or incident, and
while the investigation is pending, conduct quarterly status reviews
until completed. The post-incident summary and all other reviews and
analyses produced under the requirements of this section must be
reviewed, dated, and signed by the appropriate senior executive
officer. The post-incident summary, all investigation and analysis
documents used to prepare it, and records of lessons learned must be
kept for the useful life of the pipeline.
0
7. Section 192.634 is added to read as follows:

Sec.  192.634   Transmission lines: Onshore valve shut-off for rupture
mitigation.

    (a) Applicability. For onshore transmission pipeline segments with
nominal diameters of 6 inches or greater in high consequence areas or
Class 3 or Class 4 locations that are constructed or where 2 or more
contiguous miles have been replaced after [DATE 12 MONTHS AFTER
EFFECTIVE DATE OF FINAL RULE], an operator must install rupture-
mitigation valves according to the requirements of this section.
Rupture-

mitigation valves must be operational within 7 days of placing the new
or replaced pipeline segment in service.
    (b) Maximum spacing between valves. Rupture-mitigation valves must
be installed in accordance with the following requirements:
    (1) High Consequence Areas. For purposes of this paragraph (b)(1),
``shut-off segment'' means the segment of pipe located between the
upstream mainline valve closest to the upstream high consequence area
segment endpoint and the downstream mainline valve closest to the
downstream high consequence area segment endpoint so that the entirety
of the high consequence area segment is between at least two rupture-
mitigation valves. If any crossover or lateral pipe for gas receipts or
deliveries connects to the shut-off segment between the upstream and
downstream mainline valves, then the segment also extends to the
nearest valve on the crossover connection(s) or lateral(s), such that,
when all valves are closed, there is no flow path for gas to be
transported to the rupture site (except for residual gas already in the
shut-off segment). All such valves on a shut-off segment are ``rupture-
mitigation valves.'' Multiple high consequence areas may be contained
within a single shut-off segment. The distance between rupture-
mitigation valves for each shut-off segment must not exceed:
    (i) 8 miles if one or more high consequence areas in the shutoff
segment is in a Class 4 location;
    (ii) 15 miles if one or more high consequence areas in the shutoff
segment is in a Class 3 location, and
    (iii) 20 miles if all high consequence areas in the shutoff segment
are located in Class 1 or 2 locations, or
    (iv) The mainline valve spacing requirements of Sec.  192.179 when
mainline valve spacing does not meet Sec.  192.634(b)(1)(i), (ii), or
(iii).
    (2) Class 3 locations. For purposes of this paragraph, ``shut-off
segment'' means the segment of pipe located between the upstream
mainline valve closest to the upstream endpoint of the Class 3 location
and the downstream mainline valve closest to the downstream endpoint of
the Class 3 location so that the entirety of the Class 3 location is
between at least two rupture-mitigation valves. If any crossover or
lateral pipe for gas receipts or deliveries connects to the shut-off
segment between the upstream and downstream mainline valves, the shut-
off segment also extends to the nearest valve on the crossover
connection(s) or lateral(s), such that, when all valves are closed,
there is no flow path for gas to be transported to the rupture site
(except for residual gas already in the shut-off segment). All such
valves on a shut-off segment are ``rupture-mitigation valves.''
Multiple Class 3 locations may be contained within a single shut-off
segment. The distance between mainline valves serving as rupture-
mitigation valves for each shut-off segment must not exceed 15 miles.
    (3) Class 4 locations. For purposes of this paragraph, ``shut-off
segment'' means the segment of pipe between the upstream mainline valve
closest to the upstream endpoint of the Class 4 location and the
downstream mainline valve closest to the downstream endpoint of the
Class 4 location so that the entirety of the Class 4 location is
between at least two rupture-mitigation valves. If any crossover or
lateral pipe for gas receipts or deliveries connects to the shut-off
segment between the upstream and downstream mainline valves, the shut-
off segment also extends to the nearest valve on the crossover
connection(s) or lateral(s), such that, when all valves are closed,
there is no flow path for gas to be transported to the rupture site
(except for residual gas already in the shut-off segment). All such
valves on a shut-off segment are ``rupture-mitigation valves.''
Multiple Class 4 locations may be contained within a single shut-off
segment. The distance between mainline valves serving as rupture-
mitigation valves for each shut-off segment must not exceed 8 miles.
    (4) Laterals. Laterals extending from shut-off segments that
contribute less than 5 percent of the total shut-off segment volume may
have rupture-mitigation valves that meet the actuation requirements of
this section at locations other than mainline receipt/delivery points,
as long as all of these laterals contributing gas volumes to the shut-
off segment do not contribute more than 5 percent of the total shut-off
segment gas volume, based upon maximum flow volume at the operating
pressure.
    (c) Valve shut-off time for rupture mitigation. Upon identifying a
rupture, the operator must, as soon as practicable:
    (1) Commence shut-off of the rupture-mitigation valve or valves
which would have the greatest effect on minimizing the release volume
and other potential safety and environmental consequences of the
discharge to achieve full rupture-mitigation valve shut-off within 40
minutes of rupture identification; and
    (2) Initiate other mitigative actions appropriate for the situation
to minimize the release volume and potential adverse consequences.
    (d) Valve shut-off capability. Onshore transmission line rupture-
mitigation valves must have actuation capability (i.e., remote-control
shut-off, automatic shut-off, equivalent technology, or manual shut-off
where personnel are in proximity) to ensure pipeline ruptures are
promptly mitigated based upon maximum valve shut-off times, location,
and spacing specified in paragraphs (b) and (c) of this section to
mitigate the volume and consequence of gas released.
    (e) Valve shut-off methods. All onshore transmission line rupture-
mitigation valves must be actuated by one of the following methods to
mitigate a rupture as soon as practicable but within 40 minutes of
rupture identification:
    (1) Remote control from a location that is continuously staffed
with personnel trained in rupture response to provide immediate shut-
off following identification of a rupture or other decision to close
the valve;
    (2) Automatic shut-off following identification of a rupture; or
    (3) Alternative equivalent technology that is capable of mitigating
a rupture in accordance with this section.
    (4) Manual operation upon identification of a rupture. Operators
using a manual valve in accordance with Sec.  192.179(e), must
appropriately station personnel to ensure valve shut-off in accordance
with paragraph (c) of this section. Manual operation of valves must
include time for the assembly of necessary operating personnel, the
acquisition of necessary tools and equipment, driving time under heavy
traffic conditions and at the posted speed limit, walking time to
access the valve, and time to manually shut off all valves, not to
exceed the 40-minute total response time in paragraph (c)(1) of this
section.
    (f) Valve monitoring and operation capabilities. Onshore
transmission line rupture-mitigation valves actuated by methods in
paragraph (e) of this section must be capable of being:
    (1) Monitored or controlled by either remote or onsite personnel;
    (2) Operated during normal, abnormal, and emergency operating
conditions;
    (3) Monitored for valve status (i.e., open, closed, or partial
closed/open), upstream pressure, and downstream pressure. Pipeline
segments that use manual valve operation must have the capability to
monitor pressures and gas flow rates on the pipeline to be able to
identify and locate a rupture;
    (4) Initiated to close as soon as practicable after identifying a
rupture and with complete valve shut-off within

40 minutes of rupture identification as specified in paragraph (c) of
this section; and
    (5) Monitored and controlled by remote personnel or must have a
back-up power source to maintain SCADA or other remote communications
for remote control shut-off valve or automatic shut-off valve
operational status.
    (g) Monitoring of valve shut-off response status. Operating control
personnel must continually monitor rupture-mitigation valve position
and operational status of all rupture-mitigation valves for the
affected shut-off segment during and after a rupture event until the
pipeline segment is isolated. Such monitoring must be maintained
through continual electronic communications with remote instrumentation
or through continual verbal communication with onsite personnel
stationed at each rupture-mitigation valve, via telephone, radio, or
equivalent means.
    (h) Alternative equivalent technology or manual valves for onshore
transmission rupture mitigation. If an operator elects to use
alternative equivalent technology or manual valves in accordance with
Sec.  192.179(e), the operator must notify PHMSA at least 90 days in
advance of installation or use in accordance with Sec.  192.949. The
operator must include a technical and safety evaluation in its notice
to PHMSA, including design, construction, and operating procedures for
the alternative equivalent technology or manual valve. Operators
installing manual valves must also demonstrate that installing an
automatic shutoff valve, a remote-control valve, or equivalent
technology would be economically, technically, or operationally
infeasible. An operator may proceed to use the alternative equivalent
technology or manual valves 91 days after submitting the notification
unless it receives a letter from the Associate Administrator of
Pipeline Safety informing the operator that PHMSA objects to the
proposed use of the alternative equivalent technology or manual valves
or that PHMSA requires additional time to conduct its review.
0
8. In Sec.  192.745 paragraphs (c), (d), and (e) are added to read as
follows:

Sec.  192.745   Valve maintenance: Transmission lines.

* * * * *
    (c) For each valve installed under Sec.  192.179(e) and each
rupture-mitigation valve under Sec.  192.634 that is a remote control
shut-off or automatic shut-off valve, or that is based on alternative
equivalent technology, the operator must conduct a point-to-point
verification between SCADA displays and the mainline valve, sensors,
and communications equipment in accordance with Sec.  192.631(c) and
(e).
    (d) For each rupture-mitigation valve under Sec.  192.634 that is
manually or locally operated:
    (1) Operators must establish the 40-minute total response time as
required by Sec.  192.634 through an initial drill and through periodic
validation as required in paragraph (d)(2) of this section. Each phase
of the drill response must be reviewed and the results documented to
validate the total response time, including valve shut-off, as being
less than or equal to 40 minutes following rupture identification.
    (2) A mainline valve serving as a rupture-mitigation valve within
each pipeline system and within each operating or maintenance field
work unit must be randomly selected for an annual 40-minute total
response time validation drill that simulates worst-case conditions for
that location to ensure compliance. The response drill must occur at
least once each calendar year, with intervals not to exceed 15 months.
    (3) If the 40-minute maximum response time cannot be validated or
achieved in the drill, the operator must revise response efforts to
achieve compliance with Sec.  192.634 no later than 6 months after the
drill. Alternative valve shut-off measures must be in place in
accordance with paragraph (e) of this section within 7 days of a failed
drill.
    (4) Based on the results of response-time drills, the operator must
include lessons learned in:
    (i) Training and qualifications programs; and
    (ii) Design, construction, testing, maintenance, operating, and
emergency procedures manuals; and
    (iii) Any other areas identified by the operator as needing
improvement.
    (e) Each operator must take remedial measures to correct any valve
installed under Sec.  192.179(e) or any rupture-mitigation valve
identified in Sec.  192.634 that is found to be inoperable or unable to
maintain shut-off, as follows:
    (1) Repair or replace the valve as soon as practicable but no later
than 6 months after finding that the valve is inoperable or unable to
maintain shut-off; and
    (2) Designate an alternative compliant valve within 7 calendar days
of the finding while repairs are being made.
0
9. In Sec.  192.935, paragraph (c) is revised to read as follows:

Sec.  192.935   What additional preventive and mitigative measures must
an operator take?

* * * * *
    (c) Risk analysis for gas releases and protection against ruptures.
If an operator determines, based on a risk analysis, that an automatic
shut-off valve (ASV) or remote-control valve (RCV) would be an
efficient means of adding protection to a high consequence area in the
event of a gas release, an operator must install the ASV or RCV. In
making that determination, an operator must, at least, consider the
following factors--swiftness of leak detection and pipe shutdown
capabilities, the type of gas being transported, operating pressure,
the rate of potential release, pipeline profile, the potential for
ignition, and location of nearest response personnel.
    (1) Protection of onshore transmission high consequence areas from
ruptures. An operator of an onshore transmission pipeline segment that
is constructed, or that has 2 or more contiguous miles replaced, after
[DATE 12 MONTHS AFTER EFFECTIVE DATE OF FINAL RULE] and is greater than
or equal to 6 inches in nominal diameter and is located in a high
consequence area must provide for the additional protection of those
pipeline segments to assure the timely termination and mitigation of
rupture events by complying with Sec. Sec.  192.615(a)(6), 192.634, and
192.745. At a minimum, the analysis specified in paragraph (c) of this
section must demonstrate that the operator can achieve the following
standards for termination of rupture events:
    (i) Operators must identify a rupture event as soon as practicable
but within 10 minutes of the initial notification to or by the
operator, in accordance with Sec.  192.615(a)(6), regardless of how the
rupture is initially detected or observed;
    (ii) Operators must begin closing shut-off segment rupture-
mitigation valves as soon as practicable after identifying a rupture in
accordance with Sec.  192.634; and
    (iii) Operators must achieve complete segment shut-off and
isolation as soon as practicable after rupture detection but within 40
minutes of rupture identification in accordance with Sec.  192.634.
    (2) Compliance deadlines. The risk analysis and assessments
specified in paragraph (c) of this section must be completed prior to
placing into service onshore transmission pipelines constructed or
where 2 or more contiguous miles have been replaced after [DATE 12
MONTHS AFTER EFFECTIVE DATE OF FINAL RULE]. Implementation of risk
analysis and assessment findings for rupture-mitigation valves must
meet Sec.  192.634.
    (3) Periodic evaluations. Risk analyses and assessments conducted
under

paragraph (c) of this section must be reviewed by the operator for new
or existing operational and integrity matters that would affect rupture
mitigation on an annual basis, not to exceed a period of 15 months, or
within 3 months of an incident or safety-related condition, as those
terms are defined at Sec. Sec.  191.3 and 191.23, respectively, and
certified by the signature of a senior executive of the company.
* * * * *

PART 195--TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE

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

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

0
11. In Sec.  195.2, the definition for ``rupture'' is added in
alphabetical order to read as follows:

Sec.  195.2   Definitions.

* * * * *
    Rupture means any of the following events that involve an
uncontrolled release of a large volume of hazardous liquid or carbon
dioxide:
    (1) A release of hazardous liquid or carbon dioxide observed and
reported to the operator by its field personnel, nearby pipeline or
utility personnel, the public, local responders, or public authorities,
and that may be representative of an unintentional and uncontrolled
release event defined in paragraphs (2) or (3) of this definition;
    (2) An unanticipated or unplanned flow rate change of 10 percent or
greater or a pressure loss of 10 percent or greater, occurring within a
time interval of 15 minutes or less, unless the operator has documented
in advance of the flow rate change or pressure loss the need for a
higher flow rate change or higher pressure-change threshold due to
pipeline flow dynamics and terrain elevation changes that cause
fluctuations in hazardous liquid or carbon dioxide flow that are
typically higher than a flow rate change or pressure loss of 10 percent
in a time interval of 15 minutes or less; or
    (3) An unexplained flow rate change, pressure change,
instrumentation indication or equipment function that may be
representative of an event defined in paragraph (2) of this definition.

    Note:  Rupture identification occurs when a rupture, as defined
in this section, is first observed by or reported to pipeline
operating personnel or a controller.

* * * * *
0
12. In Sec.  195.258, paragraph (c) is added to read as follows:

Sec.  195.258   Valves: General.

* * * * *
    (c) All onshore hazardous liquid or carbon dioxide pipeline
segments with diameters greater than or equal to 6 inches that are
constructed or entirely replaced after [DATE 12 MONTHS AFTER EFFECTIVE
DATE OF FINAL RULE] must have automatic shutoff valves, remote-control
valves, or equivalent technology installed at intervals meeting the
appropriate valve location and spacing requirements of this section and
Sec.  195.260. An operator may only install a manual valve under this
paragraph if it can demonstrate to PHMSA that installing an automatic
shutoff valve, remote-control valve, or equivalent technology would be
economically, technically, or operationally infeasible. An operator
installing alternative equivalent technology or manual valves must
notify PHMSA in accordance with the procedure at Sec.  195.418(h).
Valves and technology installed under this section must meet the
requirements of Sec.  195.418(c), (d), (f), and (g).
0
13. In Sec.  195.260, paragraphs (c) and (e) are revised and paragraphs
(g) and (h) are added to read as follows:

Sec.  195.260   Valves: Location.

* * * * *
    (c) On each mainline at locations along the pipeline system that
will minimize or prevent safety risks, property damage, or
environmental harm from accidental hazardous liquid or carbon dioxide
discharges, as appropriate for onshore areas, offshore areas, or high
consequence areas. For onshore pipelines constructed or that have had 2
or more contiguous miles replaced after [DATE 12 MONTHS AFTER EFFECTIVE
DATE OF FINAL RULE], mainline valve spacing must not exceed 15 miles
for pipeline segments that could affect high consequence areas (as
defined in Sec.  195.450) and 20 miles for pipeline segments that could
not affect high consequence areas. Valves protecting high consequence
areas must be located as determined by the operator's process for
identifying preventive and mitigative measures established in Sec.
195.452(i) and by using a process, such as is set forth in Section I.B
of Appendix C of part 195, but with a maximum distance from the high
consequence area segment endpoints that does not exceed 7\1/2\ miles.
* * * * *
    (e) On each side of a water crossing that is more than 100 feet (30
meters) wide from high-water mark to high-water mark as follows, unless
the Associate Administrator finds under paragraph (e)(3) of this
section that valves or valve spacing is not necessary in a particular
case to achieve an equivalent level of safety:
    (1) Valves must either be located outside of the flood plain or
have valve actuators and other control equipment installed to not be
impacted by flood conditions; and
    (2) For multiple water crossings, valves must be located on the
pipeline upstream and downstream of the first and last water crossings
so that the total distance between the first upstream valve and last
downstream valve does not exceed 1 mile.
    (3) An operator may notify PHMSA in accordance with paragraph (h)
of this section if in a particular case the valves or valve spacing
required by this paragraph is not necessary to achieve an equivalent
level of safety. Unless the Associate Administrator finds in that
particular case the valves or valve spacing required by this paragraph
are not necessary to achieve an equivalent level of safety, the
operator must comply with the valve and valve spacing requirements of
this paragraph.
* * * * *
    (g) On each mainline highly volatile liquid (HVL) pipeline that is
located in a high population area or other populated area as defined in
Sec.  195.450 and that is constructed or that has 2 or more contiguous
miles replaced after [DATE 12 MONTHS AFTER EFFECTIVE DATE OF FINAL
RULE], with a maximum valve spacing of 7\1/2\ miles, unless the
Associate Administrator finds in a particular case that this valve
spacing is not necessary to achieve an equivalent level of safety. An
operator may notify PHMSA in accordance with paragraph (h) of this
section if in a particular case the valve spacing required by this
paragraph is not necessary to achieve an equivalent level of safety. If
the Associate Administrator informs an operator that PHMSA objects, the
operator must comply with the valve spacing requirements of this
paragraph.
    (h) An operator must provide any notification required by this
section by:
    (1) Sending the notification by electronic mail to
<EMAIL_ADDRESS>or
    (2) Sending the notification by mail to ATTN: Information Resources
Manager, DOT/PHMSA/OPS, East Building, 2nd Floor, E22-321, 1200 New
Jersey Ave. SE, Washington, DC 20590.
0
14. In Sec.  195.402, paragraphs (c)(4), (5), and (12), and (e)(1),
(4), (7), and (10) are revised to read as follows:

Sec.  195.40  2 Procedural manual for operations, maintenance, and
emergencies.

* * * * *
    (c) * * *
    (4) Determining which pipeline facilities are in areas that would
require an immediate response by the operator to prevent hazards to the
public, property, or the environment if the facilities failed or
malfunctioned, including segments that could affect high consequence
areas and valves specified in either Sec. Sec.  195.418 or
195.452(i)(4).
    (5) Investigating and analyzing pipeline accidents and failures,
including sending the failed pipe, component, or equipment for
laboratory testing or examination where appropriate, to determine the
causes and contributing factors of the failure and minimize the
possibility of a recurrence.
    (i) Post-incident lessons learned. Each operator must develop,
implement, and incorporate lessons learned from a post-accident review
into its procedures, including in pertinent operator personnel training
and qualifications programs and in design, construction, testing,
maintenance, operations, and emergency procedure manuals and
specifications.
    (ii) Analysis of rupture and valve shut-offs; preventive and
mitigative measures. If a failure or accident involves a rupture as
defined in Sec.  195.2 or a rupture-mitigation valve closure as defined
in Sec.  195.418, the operator must also conduct a post-accident
analysis of all factors impacting the release volume and the
consequences of the release, and identify and implement preventive and
mitigative measures to reduce or limit the release volume and damage in
a future failure or incident. The analysis must include all relevant
factors impacting the release volume and consequences, including, but
not limited to, the following:
    (A) Detection, identification, operational response, system shut-
off, and emergency-response communications, based on the type and
volume of the release or failure event;
    (B) Appropriateness and effectiveness of procedures and pipeline
systems, including SCADA, communications, valve shut-off, and operator
personnel;
    (C) Actual response time from rupture identification to initiation
of mitigative actions, and the appropriateness and effectiveness of the
mitigative actions taken;
    (D) Location and the timeliness of actuation of all rupture-
mitigation valves identified under Sec.  195.418; and
    (E) All other factors the operator deems appropriate.
    (iii) Rupture post-incident summary. If a failure or incident
involves a rupture as defined in Sec.  195.2 or the closure of a
rupture-mitigation valve as defined in Sec.  195.418, the operator must
complete a summary of the post-accident review required by paragraph
(c)(5)(ii) of this section within 90 days of the failure or incident,
and while the investigation is pending, conduct quarterly status
reviews until completed. The post-incident summary and all other
reviews and analyses produced under the requirements of this section
must be reviewed, dated, and signed by the appropriate senior executive
officer. The post-incident summary, all investigation and analysis
documents used to prepare it, and records of lessons learned must be
kept for the useful life of the pipeline.
* * * * *
    (12) Establishing and maintaining adequate means of communication
with the appropriate public safety answering point (9-1-1 emergency
call center), as well as fire, police, and other public officials, to
learn the responsibility, resources, jurisdictional area, and emergency
contact telephone numbers for both local and out-of-area calls of each
government organization that may respond to a pipeline emergency, and
to inform the officials about the operator's ability to respond to the
pipeline emergency and means of communication.
* * * * *
    (e) * * *
    (1) Receiving, identifying, and classifying notices of events that
need immediate response by the operator or notice to the appropriate
public safety answering point (9-1-1 emergency call center), as well as
fire, police, and other appropriate public officials, and communicating
this information to appropriate operator personnel for corrective
action.
* * * * *
    (4) Taking necessary actions, including but not limited to,
emergency shutdown, valve shut-off, and pressure reduction, in any
section of the operator's pipeline system to minimize hazards of
released hazardous liquid or carbon dioxide to life, property, or the
environment. Each operator installing valves in accordance with Sec.
195.258(c) or subject to the requirements in Sec.  195.418 must also
evaluate and identify a rupture as defined in Sec.  195.2 as being an
actual rupture event or non-rupture event in accordance with operating
procedures as soon as practicable but within 10 minutes of the initial
notification to or by the operator, regardless of how the rupture is
initially detected or observed.
* * * * *
    (7) Notifying the appropriate public safety answering point (9-1-1
emergency call center), as well as fire, police, and other public
officials, of hazardous liquid or carbon dioxide pipeline emergencies
to coordinate and share information to determine the location of the
release, including both planned responses and actual responses during
an emergency, and any additional precautions necessary for an emergency
involving a pipeline transporting a highly volatile liquid. The
operator (pipeline controller or the appropriate operator emergency
response coordinator) must immediately and directly notify the
appropriate public safety answering point (9-1-1 emergency call center)
or other coordinating agency for the communities and jurisdictions in
which the pipeline is located after the operator determines a rupture
has occurred when a release is indicated and valve closure is
implemented.
* * * * *
    (10) Actions required to be taken by a controller during an
emergency, in accordance with the operator's emergency plans and
Sec. Sec.  195.418 and 195.446.
* * * * *
0
15. Section 195.418 is added to read as follows:

Sec.  195.418   Valves: Onshore valve shut-off for rupture mitigation.

    (a) Applicability. For onshore pipeline segments that could affect
high consequence areas with nominal diameters of 6 inches or greater,
that are constructed or where 2 or more contiguous miles are replaced
after [DATE 12 MONTHS AFTER THE EFFECTIVE DATE OF THE RULE], an
operator must install rupture-mitigation valves according to the
requirements of this section and Sec.  195.260. Rupture-mitigation
valves must be operational within 7 days of placing the new or replaced
pipeline segment in service.
    (b) Maximum spacing between valves. Rupture-mitigation valves must
be installed in accordance with the following requirements:
    (1) For purposes of this section, a ``shut-off segment'' means the
segment of pipe located between the upstream mainline valve closest to
the upstream high consequence area segment endpoint and the downstream
mainline valve closest to the downstream high consequence area segment
endpoint so that the entirety of the segment that could affect the high
consequence area

is between at least two rupture-mitigation valves. If any crossover or
lateral pipe for commodity receipts or deliveries connects to the shut-
off segment between the upstream and downstream mainline valves, the
segment also extends to the nearest valve on the crossover
connection(s) or lateral(s), such that, when all valves are closed,
there is no flow path for commodity to be transported to the rupture
site (except for residual liquids already in the shut-off segment). All
such valves on a shut-off segment are ``rupture-mitigation valves.''
Multiple high consequence areas may be contained within a single shut-
off segment. All replacement pipeline segments that are over 2
continuous miles in length and could affect a high consequence area
must include a minimum of one mainline valve that meets the
requirements of this section. The distance between rupture-mitigation
valves in high consequence areas for each shut-off segment must not
exceed 15 miles, with a maximum distance not to exceed 7\1/2\ miles
from the endpoints of a shut-off segment. Valves on lines carrying
highly volatile liquids in high population areas and other populated
areas, as those terms are defined in Sec.  195.450, must have rupture-
mitigation valves spaced at a maximum distance not exceeding 7\1/2\
miles.
    (2) Lateral lines to shut-off segments that contribute less than 5
percent of the total shut-off segment commodity volume may have lateral
rupture-mitigation valves that meet the actuation requirements of this
section at locations other than mainline receipt/delivery points, as
long as all of these laterals contributing hazardous liquid or carbon
dioxide volumes to the shut-off segment do not contribute more than 5
percent of the total shut-off segment commodity volume based upon
maximum flow gradients and terrain.
    (c) Valve shut-off time for rupture mitigation. Upon identifying a
rupture, the operator must, as soon as practicable:
    (1) Commence shut-off of the rupture-mitigation valve or valves
that would have the greatest effect on minimizing the release volume
and other potential safety and environmental consequences of the
discharge to achieve full rupture-mitigation valve shut-off within 40
minutes of rupture identification; and
    (2) Initiate other mitigative actions appropriate for the situation
to minimize the release volume and potential adverse consequences.
    (d) Valve shut-off capability. Onshore rupture-mitigation valves
must have actuation capability (i.e., remote control shut-off,
automatic shut-off, equivalent technology, or manual shut-off where
personnel are in proximity) to ensure pipeline ruptures are promptly
mitigated based upon maximum valve shut-off times, location, and
spacing specified in paragraphs (b) and (c) of this section to mitigate
the volume and consequence of hazardous liquid or carbon dioxide
released.
    (e) Valve shut-off methods. All onshore rupture-mitigation valves
must be actuated by one of the following methods to mitigate a rupture
as soon as practicable but within 40 minutes of rupture identification:
    (1) Remote control from a location that is continuously staffed
with personnel trained in rupture response to provide immediate shut-
off following identification of a rupture or other decision to close
the valve;
    (2) Automatic shut-off following an identification of a rupture; or
    (3) Alternative equivalent technology that is capable of mitigating
a rupture in accordance with this section.
    (4) Manual operation upon identification of a rupture. Operators
using a manual valve in accordance with Sec.  195.258 must
appropriately station personnel to ensure valve shut-off in accordance
with paragraph (c) of this section. Manual operation of valves must
include time for the assembly of necessary operating personnel,
acquisition of necessary tools and equipment, driving time under heavy
traffic conditions and at the posted speed limit, walking time to
access the valve, and time to manually shut off all valves, not to
exceed a 40-minute total response time in paragraph (c)(1) of this
section.
    (f) Valve monitoring and operation capabilities. Onshore rupture-
mitigation valves actuated by methods in paragraph (e) of this section
must be capable of being:
    (1) Monitored or controlled by either remote or onsite personnel;
    (2) Operated during normal, abnormal, and emergency operating
conditions;
    (3) Monitored for valve status (i.e., open, closed, or partial
closed/open), upstream pressure, and downstream pressure. Pipeline
segments that use manual valve operation must have the capability to
monitor pressures and gas flow rates on the pipeline to be able to
identify and locate a rupture;
    (4) Initiated to close as soon as practicable after identifying a
rupture and with complete valve shut-off within 40 minutes of rupture
identification as specified in paragraph (c)(1) of this section; and
    (5) Monitored and controlled by remote personnel or must have a
back-up power source to maintain SCADA or other remote communications
for remote control shut-off valve or automatic shut-off valve
operational status.
    (g) Monitoring of valve shut-off response status. Operating control
personnel must continually monitor rupture-mitigation valve position
and operational status of all rupture-mitigation valves for the
affected shut-off segment during and after a rupture event until the
pipeline segment is isolated. Such monitoring must be maintained
through continual electronic communications with remote instrumentation
or through continual verbal communication with onsite personnel
stationed at each rupture-mitigation valve, via telephone, radio, or
equivalent means.
    (h) Alternative equivalent technology or manual valves for onshore
rupture mitigation. If an operator elects to use alternative equivalent
technology or manual valves in accordance with Sec.  195.258(c), the
operator must notify PHMSA at least 90 days in advance of installation
or use in accordance with Sec.  195.452(m). The operator must include a
technical and safety evaluation in its notice to PHMSA, including
design, construction, and operating procedures for the alternative
equivalent technology or manual valve. Operators installing manual
valves must also demonstrate that installing an automatic shutoff
valve, a remote-control valve, or equivalent technology in lieu of a
manual valve would be economically, technically, or operationally
infeasible. An operator may proceed to use the alternative equivalent
technology or manual valves 91 days after submitting the notification
unless it receives a letter from the Associate Administrator of
Pipeline Safety informing the operator that PHMSA objects to the
proposed use of the alternative equivalent technology or manual valves
or that PHMSA requires additional time to conduct its review.
    16. In Sec.  195.420, paragraph (b) is revised and paragraphs (d),
(e), and (f) are added to read as follows:

Sec.  195.420   Valve maintenance.

* * * * *
    (b) Each operator must, at intervals not exceeding 7\1/2\ months
but at least twice each calendar year, inspect each mainline valve to
determine that it is functioning properly. Each valve installed under
Sec.  195.258(c) or rupture-mitigation valve, as defined under Sec.
195.418, must also be partially operated as part of the inspection.
* * * * *

    (d) For each valve installed under Sec.  195.258(c) or onshore
rupture-mitigation valve identified under Sec.  195.418 that is remote-
control shut-off, automatic shut-off, or that is based on alternative
equivalent technology, the operator must conduct a point-to-point
verification between SCADA displays and the mainline valve, sensors,
and communications equipment in accordance with Sec.  195.446(c) and
(e), or perform an equivalent verification.
    (e) For each onshore rupture-mitigation valve identified under
Sec.  195.418 that is to be manually or locally operated:
    (1) Operators must establish the 40-minute total response time as
required by Sec.  195.418 through an initial drill and through periodic
validation as required by paragraph (e)(2) of this section. Each phase
of the drill response must be reviewed and the results documented to
validate the total response time, including valve shut-off, as being
less than or equal to 40 minutes.
    (2) A rupture-mitigation valve within each pipeline system and
within each operating or maintenance field work unit must be randomly
selected for an annual 40-minute total response time validation drill
simulating worst-case conditions for that location to ensure
compliance. The response drill must occur at least once each calendar
year, with intervals not to exceed 15 months.
    (3) If the 40-minute maximum response time cannot be validated or
achieved in the drill, the operator must revise response efforts to
achieve compliance with Sec.  195.418 no later than 6 months after the
drill. Alternative valve shut-off measures must be in accordance with
paragraph (f) of this section within 7 days of the drill.
    (4) Based on the results of response-time drills, the operator must
include lessons learned in:
    (i) Training and qualifications programs; and
    (ii) Design, construction, testing, maintenance, operating, and
emergency procedures manuals.
    (iii) Any other areas identified by the operator as needing
improvement.
    (f) Each operator must take remedial measures to correct any
onshore valve installed under Sec.  195.258(c) or rupture-mitigation
valve identified under Sec.  195.418 that is found inoperable or unable
to maintain shut-off as follows:
    (1) Repair or replace the valve as soon as practicable but no later
than 6 months after the finding; and
    (2) Designate an alternative compliant valve within 7 calendar days
of the finding while repairs are being made. Repairs must be completed
within 6 months.
0
17. In Sec.  195.452, paragraph (i)(4) is revised to read as follows:

Sec.  195.452   Pipeline integrity management in high consequence
areas.

* * * * *
    (i) * * *
    (4) Emergency Flow Restricting Devices (EFRD). If an operator
determines that an EFRD is needed on a pipeline segment to protect a
high consequence area in the event of a hazardous liquid pipeline
release, an operator must install the EFRD. In making this
determination, an operator must, at least, consider the following
factors--the swiftness of leak detection and pipeline shutdown
capabilities, the type of commodity carried, the rate of potential
leakage, the volume that can be released, topography or pipeline
profile, the potential for ignition, proximity to power sources,
location of nearest response personnel, specific terrain between the
pipeline segment and the high consequence area, and benefits expected
by reducing the spill size.
    (i) Where EFRDs are installed to protect HCAs on all onshore
pipelines with diameters of 6 inches or greater and that are placed
into service or that have had 2 or more contiguous miles of pipe
replaced after [insert date 12 months after effective date of this
rule], the location, installation, actuation, operation, and
maintenance of such EFRDs (including valve actuators, personnel
response, operational control centers, SCADA, communications, and
procedures) must meet the design, operation, testing, maintenance, and
rupture mitigation requirements of Sec. Sec.  195.258, 195.260,
195.402, 195.418, and 195.420.
    (ii) The EFRD analysis and assessments specified in paragraph
(i)(4) of this section must be completed prior to placing into service
all onshore pipelines with diameters of 6 inches or greater and that
are constructed or that have had 2 or more contiguous miles of pipe
replaced after [insert date 12 months after effective date of this
rule]. Implementation of EFRD findings for rupture-mitigation valves
must meet Sec.  195.418.
* * * * *

    Issued in Washington, DC on January 23, 2020, under authority
delegated in 49 CFR part 1.97.
Alan K. Mayberry,
Associate Administrator for Pipeline Safety.
[FR Doc. 2020-01459 Filed 2-5-20; 8:45 am]
 BILLING CODE 4910-60-P


[Federal Register Volume 84, Number 150 (Monday, August 5, 2019)]
[Notices]
[Page 38027]
[FR Doc No: 2019-16622]

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

DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Docket No. EL19-86-000]

New York State Public Service Commission and New York State
Energy Research and Development Authority v. New York Independent
System Operator, Inc.; Notice of Complaint

    Take notice that on July 29, 2019, pursuant to sections 206 and 306
of the Federal Power Act (FPA), 16 U.S.C. 824e and 825e and Rule 206 of
the Federal Energy Regulatory Commission's (Commission) Rules of
Practice and Procedure, 18 CFR 385.206, New York State Public Service
Commission and New York State Energy Research and Development Authority
(collectively, Complainants), filed a formal complaint against New York
Independent System Operator, Inc. (NYISO or Respondent) alleging that
application of the NYISO's buyer-side market (BSM) power mitigation
measures contained in section 23.4 of attachment H of the NYISO's
Market Administration and Control Area Services Tariff results in BSM
rules that limit full market entry and participation by Energy Storage
Resources and interfere with Federal and State policy objectives and,
therefore, are unjust and unreasonable, as more fully explained in the
complaint.
    Complainants certifies that copies of the complaint were served on
the contacts for Respondent as listed on the Commission's list of
Corporate Officials.
    Any person desiring to intervene or to protest this filing must
file in accordance with Rules 211 and 214 of the Commission's Rules of
Practice and Procedure (18 CFR 385.211 and 385.214). Protests will be
considered by the Commission in determining the appropriate action to
be taken, but will not serve to make protestants parties to the
proceeding. Any person wishing to become a party must file a notice of
intervention or motion to intervene, as appropriate. The Respondent's
answer and all interventions, or protests must be filed on or before
the comment date. The Respondent's answer, motions to intervene, and
protests must be served on the Complainants.
    The Commission encourages electronic submission of protests and
interventions in lieu of paper using the eFiling link at http://www.ferc.gov. Persons unable to file electronically should submit an
original and 5 copies of the protest or intervention to the Federal
Energy Regulatory Commission, 888 First Street NE, Washington, DC
20426.
    This filing is accessible on-line at http://www.ferc.gov, using the
eLibrary link and is available for review in the Commission's Public
Reference Room in Washington, DC. There is an eSubscription link on the
website that enables subscribers to receive email notification when a
document is added to a subscribed docket(s). For assistance with any
FERC Online service, please email<EMAIL_ADDRESS>or call
(866) 208-3676 (toll free). For TTY, call<PHONE_NUMBER>.
    Comment Date: 5:00 p.m. Eastern Time on August 19, 2019.

    Dated: July 30, 2019.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
[FR Doc. 2019-16622 Filed 8-2-19; 8:45 am]
 BILLING CODE 6717-01-P