355), 49 U.S.C. 60132, ``National Pipeline Mapping System,'' requires
the operator of a pipeline facility (except distribution lines and
gathering lines) to provide information to PHMSA. Each operator is
required to submit geospatial data appropriate for use in the NPMS or
data in a format that can be readily converted to geospatial data; the
name and address of the person with primary operational control (to be
known as its operator), and a means for a member of the public to
contact the operator for additional information about the pipeline
facilities it operates. Operators would submit the requested data
elements once and make annual updates to the data if necessary. These
data elements strengthen the effectiveness of PHMSA's risk rankings and
evaluations, which are used as a factor in determining pipeline
inspection priority and frequency; allow for more effective assistance
to emergency responders by providing them with a more reliable,
complete data set of pipelines and facilities; and provide better
support to PHMSA's inspectors by providing more accurate pipeline
locations and additional pipeline-related geospatial data that can be
linked to tabular data in PHMSA's inspection database.
    PHMSA proposes to revise this information in conjunction with
proposed regulatory changes made in the Pipeline Safety: Gas Pipeline
Leak Detection and Repair NPRM to require gas gathering operators to be
subject to NPMS reporting. PHMSA estimates that gas transmission
operators currently spend approximately 120 hours each year submitting
geospatial data through the NPMS. PHMSA estimates that, due to the
changes in this NPRM, 378 Type A, B, and C operators would be added to
the NPMS reporting community. This addition would increase the number
of responses for this information collection by 378 and increase the
overall reporting burden by 45,360 hours.

    Respondents: Operators of gas transmission, hazardous liquid, or
LNG pipeline facilities.
    Annual Reporting and Recordkeeping Burden:
    Estimated Number of Responses: 1,724 responses.
    Estimated Total Annual Burden: 207,761 hours.
    Frequency of Collection: Annually.
    6. Title: Notification Requirements for Leak Detection and Repair.
    OMB Control Number: PHMSA will request a new OMB Control No.
    Current Expiration Date: TBD.
    Abstract: A person owning or operating a natural gas pipeline
facility is required to provide information to the Secretary of
Transportation at the Secretary's request according to 49 U.S.C. 60117.
The Pipeline Safety regulations contained within 49 CFR part 192
require operators to make various notifications upon the occurrence of
certain events. The provisions covered under this ICR involve
notification requirements for operators who utilize alternative or
expanded technologies and methods when conducting leak detection and
repair activities. These notification requirements are necessary to
ensure safe operation of pipelines and ascertain compliance with gas
pipeline safety regulations. These mandatory notifications help PHMSA
to stay abreast of issues related to the health and safety of the
nation's pipeline infrastructure.
    PHMSA proposes to create this information in conjunction with
proposed regulatory changes made in the Pipeline Safety: Gas Pipeline
Leak Detection and Repair NPRM which requires operators to notify PHMSA
in various instances pertaining to leak detection and repair
activities. PHMSA expects all gas pipeline operators to be subject to
these notification requirements. PHMSA estimates that it may receive
1,000 requests on average per year from gas distribution operators to
extend the deadline for remedying leaks, with each of these requests
requiring approximately 8 hours to prepare.
    Affected Public: All gas pipeline operators.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 1,000.
    Total Annual Burden Hours: 8,000.
    Frequency of Collection: On Occasion.
    7. Title: Recordkeeping Requirements for Gas Pipeline Operators.
    OMB Control Number: 2137-0049.
    Current Expiration Date: 3/31/2025.
    Abstract: A person owning or operating a natural gas pipeline
facility is required to maintain records, make reports, and provide
information to the Secretary of Transportation at the Secretary's
request. This mandatory information collection request would require
owners and/or operators of gas pipeline systems to make and maintain
records in accordance with the requirements prescribed in 49 CFR part
192 and to provide information to the Secretary of Transportation at
the Secretary's request. Certain records are maintained for a specific
length of time while others are required to be maintained for the life
of the pipeline. PHMSA uses these records to verify compliance with
regulated safety standards and to inform the agency on possible safety
risks.
    PHMSA proposes to revise this information in conjunction with
proposed regulatory changes made in the Pipeline Safety: Gas Pipeline
Leak Detection and Repair NPRM which includes various recordkeeping
requirements for operators pertaining to leak detection and remediation
activities.
    Affected Public: All gas pipeline operators.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 3,867,101 responses.
    Total Annual Burden Hours: 1,904,157 hours.
    Frequency of Collection: On Occasion.
    Requests for copies of these information collections should be
directed to Angela Hill at [email protected]. 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.
    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 July 17, 2023.

J. Unfunded Mandates Reform Act of 1995

    The Unfunded Mandates Reform Act (UMRA, 2 U.S.C. 1501 et seq.)
requires agencies to assess the effects of Federal regulatory actions
on State, local, and Tribal governments, and the private sector. For
any NPRM or final rule that includes a Federal mandate that may result
in the expenditure by state, local, and Tribal governments, in the
aggregate of $100 million or more (in 1996 dollars) in any given year,
the agency must prepare, amongst other things, a written statement that
qualitatively and quantitatively assesses the costs and benefits of the
Federal mandate.
    PHMSA expects this NPRM would impose compliance costs of $100
million or more (in 1996 dollars) on private sector entities. PHMSA has
conducted an assessment (within the Preliminary RIA in the rulemaking
docket) of the NPRM and has preliminarily concluded that the NPRM's
proposed regulatory amendments will yield an appropriate balancing of
costs and benefits.

K. Privacy Act Statement

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

L. Executive Order 13609 and International Trade Analysis

    E.O. 13609 (``Promoting International Regulatory Cooperation'')
\308\ requires agencies consider whether the impacts associated with
significant variations between domestic and international regulatory
approaches are unnecessary or may impair the ability of American
business to export and compete internationally. In meeting shared
challenges involving health, safety, labor, security, environmental,
and other issues, international regulatory cooperation can identify
approaches that are at least as protective as those that are or would
be adopted in the absence of such cooperation. International regulatory
cooperation can also reduce, eliminate, or prevent unnecessary
differences in regulatory requirements.
---------------------------------------------------------------------------

    \308\ 77 FR 26413 (May 4, 2012).
---------------------------------------------------------------------------

    Similarly, the Trade Agreements Act of 1979 (Pub. L. 96-39), as
amended by the Uruguay Round Agreements Act (Pub. L. 103-465),
prohibits Federal

agencies from establishing any standards or engaging in related
activities that create unnecessary obstacles to the foreign commerce of
the United States. For purposes of these requirements, Federal agencies
may participate in the establishment of international standards, so
long as the standards have a legitimate domestic objective, such as
providing for safety, and do not operate to exclude imports that meet
this objective. The statute also requires consideration of
international standards and, where appropriate, that they be the basis
for U.S. standards.
    PHMSA engages with international standards setting bodies to
protect the safety of the American public. PHMSA has assessed the
effects of the NPRM and has preliminarily determined that its proposed
regulatory amendments would not cause unnecessary obstacles to foreign
trade.

M. Cybersecurity and Executive Order 14082

    E.O. 14082 (``Improving the Nation's Cybersecurity'') \309\
expressed the Administration policy that ``the prevention, detection,
assessment, and remediation of cyber incidents is a top priority and
essential to national and economic security.'' E.O. 14082 directed the
Federal Government to improve its efforts to identify, deter, and
respond to ``persistent and increasingly sophisticated malicious cyber
campaigns.'' In keeping with these policies and directives, PHMSA has
assessed the effects of this NPRM to determine what impact the proposed
regulatory amendments may have on cybersecurity risks for pipeline
facilities.
---------------------------------------------------------------------------

    \309\ 86 FR 26633 (May 17, 2021).
---------------------------------------------------------------------------

    PHMSA's proposed requirements would not require pipeline operators
to generate new security-sensitive records. Most of the pipeline
facilities for which PHMSA proposes leak detection and repair
requirements (and associated recordkeeping requirements) are already
subject to such requirements--this NPRM simply proposes to enhance and
expand those requirements. While computerized continuous or remote
monitoring systems for pipeline facilities could be more vulnerable to
cyber-attack than other technologies, the NPRM does not prescribe the
use of any particular leak detection technology within operator
advanced leak detection programs. PHMSA proposes to require operators
to evaluate remote and real-time leak detection technologies as one
potential approach when operators are designing the portfolio of
technologies to be used to satisfy the proposed ALDP requirements, but
ultimately operators can choose to adopt or decline such technologies.
    One proposal that may present relatively more cybersecurity risk is
the proposed requirement for offshore gas gathering pipelines and Types
A, B, and C gas gathering pipelines to provide geospatial data for
NPMS. If hacked by a bad actor, this information could provide
particularly sensitive information regarding the location of gas
gathering infrastructure nationwide. However, the risk associated with
hacking of NPMS data on gas gathering infrastructure appears relatively
low compared to the risks associated with unauthorized release of NPMS
data on gas transmission infrastructure. Data on gas transmission
infrastructure has long been stored in NPMS and would likely be
considered a more attractive target for bad actors given the greater
importance of transmission lines in the U.S. interstate gas supply
network.
    Operators affected by these proposed requirements may also be
subject to cybersecurity requirements and guidance under Transportation
Security Administration (TSA) Security Directives,\310\ as well as any
new requirements resulting from ongoing TSA efforts to strengthen
cybersecurity and resiliency in the pipeline sector, as discussed
within an advance notice of proposed rulemaking published in November
2022.\311\ The Cybersecurity & Infrastructure Security Agency (CISA)
and the Pipeline Cybersecurity Initiative (PCI) of the U.S. Department
of Homeland Security also conduct ongoing activities to address
cybersecurity risks to U.S. pipeline infrastructure and may introduce
other cybersecurity requirements and guidance for gas pipeline
operators.\312\
---------------------------------------------------------------------------

    \310\ E.g., TSA, ``Ratification of Security Directive,'' 86 FR
38209 (July 20, 2021) (ratifying TSA Security Directive Pipeline-
2012-01, which requires certain pipeline owners and operators to
conduct actions to enhance pipeline cybersecurity).
    \311\ TSA, ``Enhancing Surface Cyber Risk Management,'' 87 FR
74702 (Nov. 30, 2022).
    \312\ See, e.g., CISA, National Cyber Awareness System Alerts,
https://www.cisa.gov/uscert/ncas/alerts (last accessed Feb. 1,
2023).
---------------------------------------------------------------------------

    PHMSA has considered the effects of the NPRM and has preliminarily
determined that its proposed regulatory amendments would not materially
affect the cybersecurity risk profile for pipeline facilities within
the scope of the proposed amendments. PHMSA seeks comment on any other
potential cybersecurity impacts of the proposed amendments beyond the
considerations discussed here.

N. Severability

    The purpose of this proposed rule is to operate holistically in
addressing a panoply of issues related to safety and environmental
hazards on regulated pipelines, with a focus on detection, grading, and
repair of leaks. However, PHMSA recognizes that certain provisions
focus on unique topics. Therefore, PHMSA preliminarily finds that the
various provisions of this proposed rule are severable and able to
function independently if severed from each other, and thus, in the
event a court were to invalidate one or more of this proposed rule's
unique provisions, the remaining provisions should stand and continue
in effect. PHMSA seeks comment on which portions of this proposed rule
should or should not be severable.

List of Subjects

49 CFR Part 191

    Natural gas, Pipeline safety, Reporting and recordkeeping
requirements.

49 CFR Part 192

    Natural gas, Pipeline safety, Safety.

49 CFR Part 193

    Pipeline safety, Reporting and recordkeeping requirements.

    In consideration of the foregoing, PHMSA proposes to amend 49 CFR
parts 191, 192, and 193 as follows:

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

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

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

0
2. In Sec.  191.3:
0
a. Revise paragraph (1)(ii) in the definition of ``Incident''; and
0
b. Add the definition of ``Large-volume gas release'' in alphabetical
order.
    The revision and addition read as follows:

Sec.  191.3  Definitions.

* * * * *

Incident * * *

    (1) * * *
    (ii) Estimated property damage of $122,000 or more, including loss
to the operator and others, or both, but excluding each of the cost of
gas lost, the cost to acquire permits, and the cost to remove and
replace non-operator infrastructure that was not damaged by the
release. For adjustments for inflation

observed in calendar year 2021 onwards, changes to the reporting
threshold will be posted on PHMSA's website. These changes will be
determined in accordance with the procedures in appendix A to part 191.
* * * * *
    Large-volume gas release means an intentional or unintentional
release of 1 million cubic feet or more of gas from a gas pipeline
facility as that term is defined in Sec.  192.3.
* * * * *
0
3. Add Sec.  191.19 to read as follows:

Sec.  191.19  Large-volume gas release report.

    Each operator of a gas pipeline facility must report a large-volume
gas release on DOT Form PHMSA-F7100.5. Each report must be submitted
within 30 days after detection of a large-volume gas release. A large-
volume gas release report is not required if an incident report has
already been submitted under this part for the same event and the
release volume identified in the incident report is within 10 percent
of the total release volume on cessation of the release.
0
4. In Sec.  191.23, revise paragraphs (a)(9) and (b)(2) to read as
follows:

Sec.  191.23  Reporting safety-related conditions.

    (a) * * *
    (9) Any safety-related condition that could lead to an imminent
hazard to public safety and causes (either directly or indirectly by
remedial action of the operator), for purposes other than abandonment,
a 20% or more reduction in operating pressure or shutdown of operation
of a pipeline, UNGSF, or an LNG facility that contains or processes gas
or LNG.
* * * * *
    (b) * * *
    (2) Is an incident or large-volume gas release, or results in an
incident or large-volume gas release before the deadline for filing the
safety-related condition report;
* * * * *
0
5. In Sec.  191.29, revise paragraph (a) introductory text, and remove
paragraph (c) to read as follows:

Sec.  191.29  National Pipeline Mapping System.

    (a) Each operator of a gas transmission pipeline, offshore
gathering, Type A, Type B, or Type C regulated onshore gathering
pipeline as determined in Sec.  192.8 of this subchapter, or liquefied
natural gas facility must provide the following geospatial data to
PHMSA for that pipeline or facility:
* * * * *

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

0
6. 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
7. In Sec.  192.3, add the definitions of ``Confined space,'' ``Gas-
associated substructure,'' ``Leak or hazardous leak,'' ``Lower
explosive limit (LEL),'' ``Substructure,'' ``Tunnel,'' and ``Wall-to-
wall paved area'' in alphabetical order to read as follows:

Sec.  192.3  Definitions.

* * * * *
    Confined space means any subsurface structure, other than a
building, of sufficient size to accommodate a person, and in which gas
could accumulate or migrate. These include, vaults, certain tunnels,
catch basins, and manholes.
* * * * *
    Gas-associated substructure means a substructure that is part of an
operator's pipeline but that is not itself designed to contain gas.
* * * * *
    Leak or hazardous leak means, for the purposes of all subparts of
part 192 except Sec.  192.12(d) and subparts O and P, any release of
gas from a pipeline that is uncontrolled at the time of discovery and
is an existing, probable, or future hazard to persons, property, or the
environment, or any uncontrolled release of gas from a pipeline that is
or can be discovered using equipment, sight, sound, smell, or touch.
* * * * *
    Lower explosive limit (LEL) means the minimum concentration of gas
or vapor in air below which propagation of a flame does not occur in
the presence of an ignition source at ambient pressure and temperature.
* * * * *
    Substructure means any subsurface structure that is not large
enough for a person to enter and in which gas could accumulate or
migrate. Substructures include, but are not limited to, telephone and
electrical ducts, and conduit, gas and water valve boxes, and meter
boxes.
* * * * *
    Tunnel is a subsurface passageway large enough for a person to
enter and in which gas could accumulate or migrate.
* * * * *
    Wall-to-wall paved area means an area where the ground surface
between the curb of a paved street and the front wall of a building is
continuously paved, excluding intermittent landscaping, such as tree
plots.
* * * * *
0
8. In Sec.  192.9:
0
a. Revise paragraph (b);
0
b. Redesignate paragraphs (d)(4) through (8) as paragraphs (d)(6)
through (10);
0
c. Add new paragraphs (d)(4) and (5);
0
d. Remove the word ``and'' from the end of paragraph (d)(9);
0
e. Revise newly redesignated paragraph (d)(10), and add paragraphs
(d)(11) through (13);
0
f. Redesignate paragraphs (e)(1)(iii) through (vii) as paragraphs
(e)(1)(iv) through (viii);
0
g. Add new paragraph (e)(1)(iii);
0
h. Remove the word ``and'' at the end of paragraph (e)(1)(vii);
0
i. Revise newly redesignated paragraph (e)(1)(viii);
0
j. Add paragraphs (e)(1)(ix) through (xi); and
0
k. Revise paragraph (f).
    The revisions and additions read as follows:

Sec.  192.9  What requirements apply to gathering pipelines?

* * * * *
    (b) Offshore lines. An operator of an offshore gathering line must
comply with requirements of this part applicable to transmission lines,
except the requirements in Sec. Sec.  192.13(d), 192.150, 192.285(e),
192.319(d) through (g), 192.461(f) through (i), 192.465(d) and (f),
192.473(c), 192.478, 192.485(c), 192.493, 192.506, 192.607, 192.613(c),
192.619(e), 192.624, 192.710, 192.712, 192.714, 192.763(c)(1)(vi) and
(c)(3), and in subpart O of this part.
* * * * *
    (d) * * *
    (4) Prepare, update, and follow a manual of written procedures for
conducting operations, maintenance, and emergency response in
accordance with Sec.  192.605. Compliance with the requirements
referenced in Sec.  192.605(b)(1), (b)(2), (b)(12), and (e) is only
required for pipeline facilities that are made subject to such
requirements under this section or Sec.  191.23;
    (5) Develop and implement procedures for emergency plans in
accordance with Sec.  192.615;
* * * * *
    (10) Conduct leakage surveys in accordance with Sec.  192.706
within an advanced leak detection program in accordance with Sec.
192.763;
    (11) Investigate, grade, repair, and document leaks and leak
repairs in accordance with Sec. Sec.  192.703(c) through (d), 192.709,
and 192.760;

    (12) Conduct patrols in accordance with Sec.  192.705; and
    (13) Maintain and configure pressure relief devices to ensure
proper device operation and minimize release of gas in accordance with
Sec.  192.773.
    (e) * * *
    (1) * * *
    (iii) Prepare, update, and follow a manual of written procedures
for conducting operations, maintenance, and emergency response in
accordance with Sec.  192.605. Compliance with the requirements
referenced in Sec.  192.605(b)(1), (2) and (12), (d), and (e) is only
required for pipeline facilities that are made subject to such
requirements under this section or Sec.  191.23;
* * * * *
    (viii) Conduct leakage surveys in accordance with Sec. Sec.
192.706 within an advanced leak detection program in accordance with
Sec.  192.763;
    (ix) Grade, investigate, repair, and document leaks and leak
repairs in accordance with Sec. Sec.  192.703(c) and (d), 192.709, and
192.760;
    (x) Conduct patrols in accordance with Sec.  192.705; and
    (xi) Maintain and configure pressure relief devices to ensure
proper device operation and minimize release of gas in accordance with
Sec.  192.773.
* * * * *
    (f) Exceptions. (1) Compliance with paragraphs (e)(1)(ii), (vi),
and (vii), and (e)(2)(i) and (ii) of this section is not required for
pipeline segments that are 16 inches or less in outside diameter if one
of the following criteria are met:
* * * * *
0
9. In Sec.  192.12, revise paragraph (c) to read as follows:

Sec.  192.12  Underground natural gas storage facilities.

* * * * *
    (c) Procedural manuals. Each operator of an UNGSF must prepare and
follow for each facility one or more manuals of written procedures for
conducting operations, maintenance, and emergency preparedness and
response activities under paragraphs (a) and (b) of this section. Such
manuals must include procedures for eliminating leaks and minimizing
releases of gas. Each operator must keep records necessary to
administer such procedures and review and update these manuals at
intervals not exceeding 15 months, but at least once each calendar
year. Each operator must keep the appropriate parts of these manuals
accessible at locations where UNGSF work is being performed. Each
operator must have written procedures in place before commencing
operations or beginning an activity not yet implemented.
* * * * *
0
10. In Sec.  192.18, revise paragraph (c) to read as follows:

Sec.  192.18  How to notify PHMSA.

* * * * *
    (c) Unless otherwise specified, if an operator submits, pursuant to
Sec.  192.8, 192.9, 192.13, 192.179, 192.319, 192.461, 192.506(b),
192.607(e)(4), 192.607(e)(5), 192.619, 192.624(c)(2)(iii),
192.624(c)(6),192.632(b)(3), 192.634, 192.636, 192.703(d)(4),
192.706(a)(2), 192.710(c)(7), 192.712(d)(3)(iv), 192.712(e)(2)(i)(E),
192.714, 192.745, 192.760(h), 192.763(c), 192.917, 192.921(a)(7),
192.927, 192.933, or 192.937(c)(7) a notification for use of a
different integrity assessment method, analytical method, compliance
period, sampling approach, pipeline material, or technique (e.g.,
``other technology'' or ``alternative equivalent technology'') than
otherwise prescribed in those sections, that notification must be
submitted to PHMSA for review at least 90 days in advance of using the
other method, approach, compliance timeline, or technique. An operator
may proceed to use the other method, approach, compliance timeline, or
technique 91 days after submitting the notification unless it receives
a letter from PHMSA informing the operator that PHMSA objects to the
proposal or that PHMSA requires additional time and/or more information
to conduct its review.
* * * * *
0
11. In Sec.  192.167, revise paragraph (a)(2) to read as follows:

Sec.  192.167  Compressor stations: Emergency shutdown.

    (a) * * *
    (2) It must discharge gas from the blowdown piping at a location
where the gas will not create a hazard to public safety;
* * * * *
0
12. In Sec.  192.169, revise paragraph (b) as follows:

Sec.  192.169  Compressor stations: Pressure limiting devices.

* * * * *
    (b) Each vent line that exhausts gas from the pressure relief
valves of a compressor station must extend to a location where the gas
may be discharged without hazard to public safety.
* * * * *
0
13. In Sec.  192.179, revise paragraph (c) to read as follows:

Sec.  192.179  Transmission line valves.

* * * * *
    (c) Each section of a transmission line, other than offshore
segments, between main line valves must have a blowdown valve with
enough capacity to allow the transmission line to be blown down as
rapidly as practicable. Each blowdown discharge must be located so the
gas can be blown to the atmosphere without hazard to public safety and,
if the transmission line is adjacent to an overhead electric line, so
that the gas is directed away from the electrical conductors.
* * * * *
0
14. In Sec.  192.199, revise the section heading and paragraph (e), and
add paragraph (i) to read as follows:

Sec.  192.199  Requirements for design and configuration of pressure
relief and limiting devices.

* * * * *
    (e) Have discharge stacks, vents, or outlet ports designed to
prevent accumulation of water, ice, or snow, located where gas can be
discharged into the atmosphere without undue hazard to public safety;
* * * * *
    (i) All new, replaced, relocated, or otherwise changed pressure
relief and limiting devices must be designed and configured, as
demonstrated by a documented engineering analysis, to minimize
unnecessary releases of gas by ensuring each of the following:
    (1) The set and reset actuation pressure of the pressure relief
device and where pressures are taken must minimize release volumes
beyond what is necessary to provide adequate overpressure protection;
    (2) The design (including sizing and material) and configuration of
the pressure relief device and its associated piping must be
appropriate for its set and reset actuation pressure to minimize
pressure choking, compatible with the composition of transported gas,
and suitable for reliable operation in expected operating and
environmental conditions; and
    (3) Installation of the pressure relief device must include
upstream and downstream isolation valves to facilitate testing and
maintenance.
0
15. In Sec.  192.361, revise paragraph (f)(3) to read as follows:

Sec.  192.361  Service lines: Installation.

* * * * *
    (f) * * *
    (3) The space between the conduit and the service line must be
sealed to prevent gas leakage into the building and, if the conduit is
sealed at both ends, a vent line from the annular space must extend to
a point where gas would not be a hazard to public safety, and

extend above grade, terminating in a rain and insect resistant fitting.
* * * * *
0
16. In Sec.  192.363, revise paragraph (c) to read as follows:

Sec.  192.363  Service lines: Valve requirements.

* * * * *
    (c) Each service-line valve on a high-pressure service line,
installed above ground or in an area where the blowing of gas would be
hazardous to public safety, must be designed and constructed to
minimize the possibility of the removal of the core of the valve with
other than specialized tools.
0
17. In Sec.  192.503 revise paragraph (a)(2) to read as follows:

Sec.  192.503  General requirements.

    (a) * * *
    (2) Each hazardous leak has been located and eliminated.
* * * * *
0
18. In Sec.  192.507, revise paragraph (a) to read as follows:

Sec.  192.507  Test requirements for pipelines to operate at a hoop
stress less than 30 percent of SMYS and at or above 100 p.s.i. (689
kPa) gage.

* * * * *
    (a) The pipeline operator must use a test procedure that will
ensure discovery of all hazardous leaks in the segment being tested.
* * * * *
0
19. In Sec.  192.509, revise paragraph (a) to read as follows:

Sec.  192.509  Test requirements for pipelines to operate below 100
p.s.i. (689 kPa) gage.

* * * * *
    (a) The test procedure used must ensure discovery of all hazardous
leaks in the segment being tested.
* * * * *
0
20. In Sec.  192.513, revise paragraph (b) to read as follows:

Sec.  192.513  Test requirements for plastic pipelines.

* * * * *
    (b) The test procedure must ensure discovery of all hazardous leaks
in the segment being tested.
* * * * *
0
21. In Sec.  192.553, revise paragraph (a)(2) to read as follows:

Sec.  192.553  General requirements.

* * * * *
    (a) * * *
    (2) Each leak detected must be repaired before a further pressure
increase is made.
* * * * *
0
22. In Sec.  192.557, revise paragraph (b)(2) to read as follows:

Sec.  192.557  Uprating: Steel pipelines to a pressure that will
produce a hoop stress less than 30 percent of SMYS: plastic, cast iron,
and ductile iron pipelines.

* * * * *
    (b) * * *
    (2) Make a leakage survey (if it has been more than 1 year since
the last survey) and repair any leaks that are found.
* * * * *
0
23. In Sec.  192.605, add paragraph (b)(13) to read as follows:

Sec.  192.605  Procedural manual for operations, maintenance, and
emergencies.

* * * * *
    (b) * * *
    (13) Eliminating leaks and minimizing releases of gas from
pipelines, as well as remediating or replacing pipelines known to leak
based on their material, design, or past operating and maintenance
history.
* * * * *
0
24. In Sec.  192.617, add paragraph (e) to read as follows:

Sec.  192.617  Investigation of failures and incidents.

* * * * *
    (e) Failure defined. For the purposes of this section, the term
failure means when any portion of a pipeline becomes inoperable, is
incapable of safely performing its intended function, or has become
unreliable or unsafe for continued use.
0
25. In Sec.  192.629, revise paragraphs (a) and (b) to read as follows:

Sec.  192.629  Purging of pipelines.

    (a) When a pipeline is being purged of air by use of gas, the gas
must be introduced into one end of the pipeline in a moderately rapid
and continuous flow. If gas cannot be supplied in sufficient quantity
to prevent the formation of a mixture of gas and air hazardous to
public safety, a slug of inert gas must be introduced into the pipeline
before the gas.
    (b) When a pipeline is being purged of gas by use of air, the air
must be introduced into one end of the line in a moderately rapid and
continuous flow. If air cannot be supplied in sufficient quantity to
prevent the formation of a mixture of gas and air hazardous to public
safety, a slug of inert gas must be released into the line before the
air.
0
26. In Sec.  192.703, revise paragraph (c), and add paragraph (d) to
read as follows:

Sec.  192.703  General.

* * * * *
    (c) Leaks must be graded and repaired in accordance with the
requirements in Sec.  192.760.
    (d) Compliance with Sec. Sec.  192.703(c), 192.705 for patrols,
192.706 for leakage surveys, 192.760(a) through (h) for leak grading
and repair, 192.763 for advanced leak detection programs, and 192.769
for qualification of leakage survey personnel, is not required for a
compressor station on a gas transmission or gathering pipeline if:
    (1) The facility is subject to methane emission monitoring and
repair requirements under either:
    (i) 40 CFR part 60, subparts OOOOa or OOOOb; or
    (ii) an EPA-approved State plan or Federal plan which includes
relevant standards at least as stringent as EPA's finalized emissions
guidelines in 40 CFR part 60, subpart OOOOc;
    (2) The facility is within the first block valve entering or
exiting the compressor station covered by the emergency shutdown system
as required in Sec.  192.167 for station isolation from the pipeline;
and
    (3) Repair records are maintained for the life of the facility in
accordance with Sec.  192.760(i).
0
27. In Sec.  192.705, revise paragraph (b) to read as follows:

Sec.  192.705  Transmission lines: Patrolling.

* * * * *
    (b) Operators must conduct patrols at least 12 times each calendar
year at intervals not exceeding 45 days.
* * * * *
0
28. Revise Sec.  192.706 to read as follows:

Sec.  192.706  Transmission lines: Leakage surveys.

    (a) General. Each operator must perform periodic leakage surveys in
accordance with this section. Each leakage survey must be conducted
according to the advanced leak detection program requirements in Sec.
192.763, except that human or animal senses may be used in lieu of leak
detection equipment only in the following circumstances:
    (1) An offshore gas transmission pipeline below the waterline or
offshore gathering pipeline below the waterline; or
    (2) An onshore transmission line outside of an HCA or a gathering
pipeline, each either in a Class 1 or Class 2 location, with advance
notification to PHMSA in accordance with Sec.  192.18. The notification
must include tests or analyses demonstrating that the survey method
would meet the ALDP performance standard in Sec.  192.763(b) or (c) (as
applicable).

    (b) Frequency of surveys. Except as provided in paragraphs (c) and
(d) of this section, leakage surveys must be performed at the following
intervals:
    (1) Pipelines outside of HCAs must be surveyed at least once per
calendar year, but with an interval between surveys not to exceed 15
months; and
    (2) Pipelines in HCAs must be surveyed as follows:
    (i) In Class 1, Class 2, and Class 3 locations, at least twice each
calendar year, with intervals not exceeding 7\1/2\ months;
    (ii) In Class 4 locations, at least four times each calendar year,
with intervals not exceeding 4\1/2\ months.
    (c) Non-odorized pipelines. Leakage surveys for pipelines
transporting gas in conformity with Sec.  192.625 without an odor or
odorant, must perform leakage surveys using leak detection equipment at
the following intervals:
    (1) In Class 3 locations, at least twice each calendar year, at
intervals not exceeding 7\1/2\ months.
    (2) In Class 4 locations, at least four times each calendar year,
at intervals not exceeding 4\1/2\ months.
    (d) Valves, flanges and certain other facilities. Leakage surveys
of all valves, flanges, pipeline tie-ins with valves and flanges, ILI
launcher and ILI receiver facilities, and pipelines known to leak based
on material (including, cast iron, unprotected steel, wrought iron, and
historic plastics with known issues), design, or past operating and
maintenance history, must be performed at the following intervals:
    (1) In Class 1, Class 2, and Class 3 locations, at least twice each
calendar year, at intervals not exceeding 7\1/2\ months.
    (2) In Class 4 locations, at least four times each calendar year,
at intervals not exceeding 4\1/2\ months.
0
29. Revise Sec.  192.723 to read as follows:

Sec.  192.723  Distribution systems: Leakage surveys.

    (a) General. Each operator of a gas distribution pipeline must
conduct periodic leakage surveys with leak detection equipment in
accordance with this section. All leakage surveys performed pursuant to
this section must use leak detection equipment that meets the
requirements of Sec.  192.763.
    (b) Business districts. Leakage surveys must be conducted at least
once each calendar year, at intervals not exceeding 15 months,
consisting of atmospheric tests at each gas, electric, telephone,
sewer, water, or other system manhole; crack in the pavement and
sidewalks; and any other location that provides an opportunity for
finding gas leaks.
    (c) Non-business districts. Leakage surveys must be conducted at
least once every 3 calendar years, at intervals not exceeding 39
months, unless a shorter inspection interval is required either by
paragraph (d) of this section, the operator's operations and
maintenance procedures, or the operator's integrity management plans
under part 192, subpart P.
    (d) Frequency of regular leakage surveys. Leakage surveys must be
conducted at least once every calendar year, at intervals not exceeding
15 months, for:
    (1) Cathodically unprotected distribution pipelines subject to
Sec.  192.465(e);
    (2) Pipelines known to leak based on their material (including cast
iron, unprotected steel, wrought iron, and historic plastics with known
issues), design, or past operating and maintenance history; and
    (3) Gas distribution pipeline systems protected by a distributed
anode system, in the area of deficient readings identified during a
cathodic protection survey pursuant to Sec.  195.463 and appendix D,
until the cathodic protection deficiency is remediated.
    (e) Investigating known leaks after environmental changes. An
operator must investigate a known leak, including conducting a leakage
survey for possible gas migration, as soon as practicable when freezing
ground, heavy rain, flooding, or other changes to the environment occur
that could affect the venting of gas or could cause migration of gas to
the outside wall of a building.
    (f) Extreme Weather Surveys. Leakage surveys must be performed
after extreme weather events and land movement with the likelihood to
cause damage to the affected pipeline segment. The survey must be
initiated within 72 hours after the cessation of the event, defined as
either the point in time when the affected area can be safely accessed
by the personnel and equipment required to perform the leakage survey
or when the facility has been returned to service.
0
30. In Sec.  192.727, revise paragraphs (b) and (c) to read as follows:

Sec.  192.727  Abandonment or deactivation of facilities.

* * * * *
    (b) Each pipeline abandoned in place must be disconnected from all
sources and supplies of gas; purged of gas; in the case of offshore
pipelines, filled with water or inert materials; and sealed at the
ends. However, the pipeline need not be purged when the volume of gas
is so small that there is no potential hazard to public safety.
    (c) Except for service lines, each inactive pipeline that is not
being maintained under this part must be disconnected from all sources
and supplies of gas; purged of gas; in the case of offshore pipelines,
filled with water or inert materials; and sealed at the ends. However,
the pipeline need not be purged when the volume of gas is so small that
there is no potential hazard to public safety.
* * * * *
0
31. In Sec.  192.751, revise paragraph (a) to read as follows:

Sec.  192.751  Prevention of accidental ignition.

* * * * *
    (a) When an amount of gas potentially hazardous to public safety is
being vented into open air, each potential source of ignition must be
removed from the area and a fire extinguisher must be present.
* * * * *
0
32. Add Sec.  192.760 to read as follows:

Sec.  192.760  Leak grading and repair.

    (a) General. Each operator must have and follow written procedures
for grading and repairing leaks that meet or exceed the requirements of
this section.
    (1) These requirements are applicable to leaks on all portions of a
gas pipeline including, but not limited to, line pipe, valves, flanges,
meters, regulators, tie-ins, launchers, and receivers.
    (2) The leak grading and repair procedure must prioritize leaks by
the hazard to public safety and the environment.
    (3) Each leak must be investigated immediately and continuously
until a leak grade determination has been made.
    (b) Grade 1 leaks. (1) A grade 1 leak is any leak that constitutes
an existing or probable hazard to persons or property or a grave hazard
to the environment. A grade 1 leak includes a leak with any of
following characteristics:
    (i) Any leak that, in the judgment of operating personnel at the
scene is regarded as an existing or probable hazard to public safety or
a grave hazard to the environment;
    (ii) Any amount of escaping gas has ignited;
    (iii) Any indication that gas has migrated into a building, under a
building, or into a tunnel;
    (iv) Any reading of gas at the outside wall of a building, or areas
where gas could migrate to an outside wall of a building;
    (v) Any reading of 80% or greater of the LEL (60% for LPG systems)
in a confined space;

    (vi) Any reading of 80% or greater of the LEL (60% for LPG systems)
in a substructure, (including gas associated substructures) from which
any gas could migrate to the outside wall of a building;
    (vii) Any leak that can be seen, heard, or felt; or
    (viii) Any leak defined as an incident in Sec.  191.3.
    (2) An operator must promptly repair a grade 1 leak and eliminate
the hazardous conditions by taking immediate and continuous action by
operator personnel at the scene. Immediate action means the operator
will begin instant efforts to remediate and repair the leak upon
detection and to eliminate any hazardous conditions caused by the leak.
Continuous means that the operator must maintain on-site remediation
efforts until the leak repair has been completed. This may require one
or more of, but not limited to, the following actions be taken without
delay:
    (i) Implementing an emergency plan pursuant to Sec.  192.615;
    (ii) Evacuating premises;
    (iii) Blocking off an area;
    (iv) Rerouting traffic;
    (v) Eliminating sources of ignition;
    (vi) Venting the area by removing manhole covers, bar holing,
installing vent holes, or other means;
    (vii) Stopping the flow of gas by closing valves or other means; or
    (viii) Notifying emergency responders.
    (c) Grade 2 leaks. (1) A grade 2 leak constitutes a probable future
hazard to persons or property or a significant hazard to the
environment, and includes any leak (other than a grade 1 leak) with any
the following characteristics:
    (i) A reading of 40% or greater of the LEL under a sidewalk in a
wall-to-wall paved area that does not qualify as a grade 1 leak;
    (ii) A reading at or above 100% of LEL under a street in a wall-to-
wall paved area that has gas migration and does not qualify as a grade
1 leak;
    (iii) A reading between 20% and 80% of the LEL in a confined space;
    (iv) A reading less than 80% of the LEL in a substructure (other
than gas associated substructures) from which gas could migrate;
    (v) A reading of 80% or greater of the LEL in a gas associated
substructure from which gas could not migrate;
    (vi) Any reading of gas that does not qualify as a grade 1 leak
that occurs on a transmission pipeline or a Type A or Type C regulated
gas gathering line;
    (vii) Any leak with a leakage rate of 10 cubic feet per hour (CFH)
or more that does not qualify as a grade 1 leak;
    (viii) Any leak of LPG or hydrogen gas that does not qualify as a
grade 1 leak; or
    (ix) Any leak that, in the judgment of operating personnel at the
scene, is of sufficient magnitude to justify scheduled repair within
six months or less.
    (2) An operator must schedule repair based on the severity or
likelihood of hazard to persons, property, or the environment. A grade
2 leak must be repaired within six months of detection, unless a
shorter repair deadline is required by the operator's procedures,
integrity management program, or paragraphs (c)(3) through (6) of this
section. The operator must re-evaluate each grade 2 leak at least once
every 30 days until it is repaired.
    (3) The operator must complete repair of any grade 2 leak on a gas
transmission or Type A gathering pipeline, each located in an HCA,
Class 3 or Class 4 location, within 30 days of detection. If repair
cannot be completed within 30 days due to permitting requirements or
parts availability, the operator must take continuous action to monitor
and repair the leak.
    (4) Each operator's operations and maintenance procedure must
include a methodology for prioritizing the repair of grade 2 leaks,
including criteria for leaks that warrant repair within 30 days of
detection pursuant to Sec.  192.760(c). Grade 2 leaks with a repair
deadline of less than 30 days must be re-evaluated at least once every
2 weeks until the repair is complete. This methodology must include an
analysis of, at a minimum, each of the following parameters:
    (i) The volume and migration of gas emissions;
    (ii) The proximity of gas to buildings and subsurface structures;
    (iii) The extent of pavement; and
    (iv) Soil type and conditions, such as frost cap, moisture, and
natural venting.
    (5) Each operator must take immediate and continuous action to
complete repair of a grade 2 leak and eliminate the hazard when
freezing ground, heavy rain, flooding, new pavement, or other changes
to the environment are anticipated or occur near an existing grade 2
leak that may affect the venting or migration of gas and could allow
gas to migrate to the outside wall of a building.
    (6) An operator must complete repair of known grade 2 leaks
existing on or before [effective date of the final rule] before [date 1
year after the publication date of the final rule].
    (d) Grade 3 leaks. (1) A grade 3 leak is any leak that does not
meet the criteria of a grade 1 or grade 2 leak. In order to qualify as
a grade 3 leak, none of the criteria for grade 1 or 2 leaks must be
present. Grade 3 leaks may include, but are not limited to, leaks with
the following characteristics:
    (i) A reading of less than 80% of the LEL in gas associated
substructures from which gas is unlikely to migrate; or
    (ii) Any reading of gas under pavement outside of a wall-to-wall
paved area where gas is unlikely to migrate to the outside wall of a
building; or
    (iii) A reading of less than 20% of the LEL in a confined space.
    (2) A grade 3 leak must be repaired within 24 months of detection,
except as described below:
    (i) A grade 3 leak known to exist on or before [effective date of
the final rule] must be repaired prior to [date 3 years after the
publication date of the final rule].
    (ii) A grade 3 leak may be evaluated in accordance with paragraph
(d)(3) of this section and repairs postponed if the segment containing
the leak is scheduled for replacement, and is replaced, within five
years of detection of the leak.
    (3) Each operator must re-evaluate each grade 3 leak at least once
every six months until repair of the leak is complete.
    (e) Post-repair inspection. (1) A leak repair is considered to be
complete when an operator obtains a gas concentration reading of 0% gas
at the leak location after a permanent repair.
    (2) An operator must conduct a post-repair leak inspection at least
14 days after but no later than 30 days after the date of the repair to
determine if the repair was complete.
    (3) If a post-repair inspection shows a gas concentration reading
greater than 0% gas, the repair is not complete, and operator must take
the following actions:
    (i) If the post repair inspection finds gas concentrations or
migration indicating that the potential for a grade 1 or grade 2
condition leak exists, the operator must re-inspect the repair and take
immediate and continuous action to eliminate the hazard and complete
repair;
    (ii) If the operator's post repair inspection does not find a gas
concentration reading of 0% at the leak location, and a grade 1 or
grade 2 condition does not exist, then the operator must remediate the
repair and re-inspect the leak within 30 days and continue reevaluating
the leak at least once every 30 days until there is a gas concentration
reading of 0%. Leak repair must be complete within the repair deadline
for a grade 3 leak under Sec.  192.760(d)(2), or for a downgraded leak,
the repair deadline under Sec.  192.760(g).

    (4) A post repair inspection is not required for any leak that is
eliminated by routine maintenance work--such as adjustment or
lubrication of above-ground valves, or tightening of packing nuts on
valves with seal leaks--and is a grade 3 leak or occurs on an
aboveground pipeline facility.
    (f) Upgrading leak grades. If at any time an operator receives
information that a higher-priority grade condition exists in connection
with a previously-graded leak, the operator must upgrade that leak to
the higher-priority grade. When an operator upgrades a leak to a
higher-priority grade, the time period to complete the repair is the
earlier of either the remaining time based on its original leak grade
or the time allowed for repair under its new leak grade measured from
the time the operator received the information that a higher-priority
grade condition exists.
    (g) Downgrading leak grades. A leak may not be downgraded to a
lower-priority leak grade unless a temporary repair to the pipeline has
been made or a permanent repair was attempted but gas was detected
during the post-repair inspection under paragraph (e) of this section.
In this case, the time period for repair is the remaining time allowed
for repair under its new grade measured from the time the leak was
detected.
    (h) Extension of leak repair. An operator may request an extension
of the leak repair deadline requirements for an individual grade 3 leak
with advance notification to and no objection from PHMSA pursuant to
Sec.  192.18. The operator's notification must show that the delayed
repair timeline would not result in an increased risk to public safety,
as well as that either the required repair deadline is impracticable,
or that remediation within the specified time frame would result in the
release of more gas to the environment than would occur with continued
monitoring. The notification must include the following:
    (1) A description of the leaking facility including the location,
material properties, the type of equipment that is leaking, and the
operating pressure;
    (2) A description of the leak and the leak environment, including
gas concentration readings, leak rate if known, class location, nearby
buildings, weather conditions, soil conditions, and other conditions
that could affect gas migration, such as pavement;
    (3) A description of the alternative repair schedule and a
justification for the same; and
    (4) Proposed emissions mitigation methods, monitoring, and repair
schedule.
    (i) Recordkeeping. (1) Records of the complete history of the
investigation and grading of each leak must be retained for 5 years
after the final post-repair inspection is completed under paragraph (e)
of this section. These records include all records documenting leak
grading, monitoring, inspections, upgrades, and downgrades.
    (2) Records of the detection, remediation, and repair of the leak
must be retained for the life of the pipeline. This must include the
date, location, and description of each leak detected, and repair or
remediation of the same, made on the pipeline.
0
33. Add Sec.  192.763 to read as follows:

Sec.  192.763  Advanced Leak Detection Program.

    (a) Advanced Leak Detection Program (ALDP) elements. Each operator
must have and follow a written ALDP that includes the following
elements:
    (1) Leak detection equipment. (i) The ALDP must include a list of
leak detection equipment used in operator leakage surveys, pinpointing
leak locations, and investigating leaks.
    (ii) Leak detection equipment used for leakage surveys, pinpointing
leak locations, investigating, and inspecting leaks must have a minimum
sensitivity of 5 parts per million for each gas being surveyed. The
operator must validate the sensitivity of this equipment before using
the device in a leakage survey by testing with a known concentration of
gas.
    (iii) Leak detection equipment must be selected based on a
documented analysis considering, at a minimum, the state of
commercially available leak detection technologies and practices, the
size and configuration of the pipeline system, and system operating
parameters and environment. At a minimum, operators must analyze the
effectiveness of the following technologies for their systems:
    (A) The use of handheld leak detection equipment capable of
detecting and locating all leaks of 5 parts per million or more when
measured within 5 feet of the pipeline or within a wall-to-wall paved
area, in conjunction with locating equipment to verify the tools are
sampling the area within 5 feet of the buried pipeline. The procedure
must include sampling the atmosphere near cracks, vaults, or any other
surface feature where gas could migrate;
    (B) Periodic surveys performed with leak detection equipment
mounted on mobile, aerial, or satellite-based platforms that, in
conjunction with confirmation by hand-held equipment, is capable of
detecting and pinpointing all leaks of 5 parts per million or more when
measured within 5 feet of the pipeline, or within a wall-to-wall paved
area;
    (C) Periodic surveys performed with optical, infrared, or laser-
based leak detection equipment that can sample or inspect the area
within 5 feet of the pipeline, or within a wall-to-wall paved area,
capable of detecting and pinpointing all leaks of 5 parts per million
or more;
    (D) Continuous monitoring for leaks via stationary sensors,
pressure monitoring, or other means that provide alarms or alerts and
that, in conjunction with confirmation by hand-held equipment, is
capable of detecting and pinpointing all leaks of 5 parts per million
or more when measured within 5 feet of the pipeline, or within a wall-
to-wall paved area; and
    (E) Systematic use of other commercially available technology
capable of detecting and pinpointing all leaks producing a reading of 5
parts per million or more within 5 feet of the pipeline, or within a
wall-to-wall paved area.
    (2) Leak detection practices. At a minimum, an operator must have
and follow written procedures for:
    (i) Performing leakage surveys. Operators must have procedures for
performing leakage surveys required for Sec. Sec.  192.706 and 192.723
using each selected leak detection technology as described in paragraph
Sec.  192.763(a)(1). The procedures must define environmental and
operational conditions for which each leak detection technology is and
is not permissible. The operator's procedures must follow the leak
detection equipment manufacturer's instructions for survey methods and
allowable environmental and operational parameters.
    (ii) Pinpointing and investigating leaks. The location of the
source of each leak indication on an onshore pipeline or any portion of
an offshore pipeline above the waterline must be pinpointed and
investigated with handheld leak detection equipment. Leak indications
on offshore pipelines below the waterline may be pinpointed with human
senses.
    (iii) Validating performance. Operators must have procedures
validating that leak detection equipment meets the requirement of
paragraph (a)(1)(ii) of this section. The operator must have procedures
for validating the sensitivity of the equipment before initial use by
testing with a known concentration of gas and at the required offset
conditions of 5 feet. Records validating equipment performance must be
maintained for five years after the

date the device is no longer used by the operator.
    (iv) Maintaining and calibrating leak detection equipment. At a
minimum, procedures must follow the equipment manufacturer's
instructions for calibration and maintenance. Leak detection equipment
must be recalibrated or replaced following any indication of
malfunction. Records validating equipment calibration and failures
indicating recalibration is necessary must be maintained for 5 years
after the date the individual device is retired by the operator.
    (3) Leakage survey frequency. Leakage survey frequency must be
sufficient to detect all leaks that have a sufficient release rate to
produce a reading of 5 parts per million or more of gas when measured
from a distance of 5 feet or less from the pipeline, or within a wall-
to-wall paved area, but may be no less frequent than required in
Sec. Sec.  192.706 and 192.723. Less sensitive equipment, challenging
survey conditions, or facilities known to leak based on their material,
design, or past operating and maintenance history may require more
frequent surveys to detect leaks consistent with paragraph (b) of this
section.
    (4) Periodic evaluation and improvement. The ALDP must include
procedures and records showing the operator is meeting all of the
program requirements.
    (i) The operator must evaluate the ALDP at least once each calendar
year but with a maximum interval not to exceed 15 months.
    (ii) The operator must make changes to any program elements
necessary to locate and eliminate leaks and minimize releases of gas.
    (iii) When considering changes to program elements, operators must
analyze, at a minimum, the performance of the leak detection equipment
used, the adequacy of the leakage survey procedures, advances in leak
detection technologies and practices, the number of leaks that are
initially detected by the public, the number of leaks and incidents,
and estimated emissions from leaks detected pursuant to this section.
    (iv) The operator must document any improvements needed to the
program.
    (b) Advanced leak detection performance standard. Each operator's
ALDP described in paragraph (a) of this section must be capable of
detecting all leaks that have a sufficient release rate to produce a
reading of 5 parts per million or more of gas when measured from a
distance of 5 feet or less from the pipeline, or within a wall-to-wall
paved area.
    (1) The performance of the ALDP must be validated and documented
with engineering tests and analyses.
    (2) Records validating that the ALDP meets the performance standard
must be maintained for at least 5 years after the date that ALDP is no
longer used by the operator.
    (c) Alternative advanced leak detection performance standard. For
gas pipelines other than natural gas pipelines, and for natural gas
transmission, offshore gathering, and Types A, B, and C gathering
pipelines located in Class 1 or Class 2 locations, an operator may use
an alternative ALDP performance standard (and supporting leak detection
equipment) with prior notification to, and with no objection from,
PHMSA in accordance with Sec.  192.18. PHMSA will only approve a
notification if operator, in the notification, demonstrates that the
alternative performance standard is consistent with pipeline safety and
equivalent to the standard in paragraph (b) of this section for
reducing greenhouse gas emissions and other environmental hazards. The
notification must include:
    (1) Mileage by system type;
    (2) Known material properties, location, HCAs, operating
parameters, environmental conditions, leak history, and design
specifications, including coating, cathodic protection status, and pipe
welding or joining method;
    (3) The proposed performance standard;
    (4) Any safety conditions, such as increased survey frequency;
    (5) The leak detection equipment, procedures, and leakage survey
frequencies the operator proposes to employ;
    (6) Data on the sensitivity and the leak detection performance of
the proposed alternative ALDP standard; and
    (7) The gas transported by the pipeline.
0
34. Add Sec.  192.769 to read as follows:

Sec.  192.769  Qualification of leakage survey, investigation, grading,
and repair personnel.

    Only individuals qualified under subpart N of this part may conduct
leakage survey, investigation, grading, and repair. Individuals
qualified under subpart N must also possess training, experience, and
knowledge in the field of leakage survey, leak investigation, and leak
grading, including documented work history or training associated with
those activities.
0
35. Add Sec.  192.770 to read as follows:

Sec.  192.770  Minimizing emissions from gas transmission pipeline
blowdowns.

    (a) Except as provided in paragraph (b) of this section, when an
operator performs any intentional release of gas (including blowdowns
or venting for scheduled repairs, construction, operations, or
maintenance) from a gas transmission pipeline, the operator must
prevent or minimize the release of gas to the environment through one
or more of the following methods:
    (1) Isolating the smallest section of the pipeline necessary to
complete the task by use of valves or the installation of control
fittings;
    (2) Routing gas released from the pipeline from the nearest
isolation valves or control fittings to a flare or to other equipment
as fuel gas;
    (3) Reducing pressure by use of in-line compression;
    (4) Reducing pressure by use of mobile compression to a segment or
storage vessel adjacent to the nearest isolation valves;
    (5) Transferring the gas to a segment of a lower pressure pipeline
system adjacent to the nearest isolation valves; or
    (6) Employing an alternative method demonstrated to result in a
release volume reduction of at least 50% compared to venting gas
directly to the atmosphere without mitigative action.
    (b) An operator is not required to comply with the provisions of
paragraph (a) of this section during an event that activates its
emergency plan under Sec.  192.615(a)(3) when such minimization would
delay emergency response or result in a safety risk during pipeline
assessments or maintenance. Each emergency release conducted without
mitigation must be documented, including the justification for release
without mitigation.
    (c) Operators must document the methodologies used in paragraph (a)
of this section and describe how the methodologies minimize the release
of gas to the environment.
0
36. Add Sec.  192.773 to read as follows:

Sec.  192.773  Pressure relief device maintenance and adjustment of
configuration.

    (a) Each operator must develop, maintain, and follow written
operations and maintenance procedures to assess the proper function of
pressure limiting or relief device and to repair or replace each failed
pressure limiting or relief device. When a pressure limiting or relief
device fails to operate or allows gas to release to the atmosphere at
an operating pressure above or below the set actuation pressure range
defined for the device in the operator's operations

and maintenance procedure, the operator must:
    (1) Assess the pilot, springs, seats, pressure gauges, and other
components to ensure proper functioning, sensing, and set/reset
actuation pressures are within actuation pressure tolerances;
    (2) Assess the inlet and outlet piping for piping that restricts
the inlet or outlet gas flow, piping that restricts the sensing
pressure, debris, and other restrictions that could impede the
operation or restrict the capacity to relieve overpressure conditions;
    (3) Repair or replace the device to eliminate the malfunction as
follows:
    (i) If a pressure relief device activates above its set pressure
and above the pressure limits in Sec.  192.201(a) or 192.739 as
applicable, fails to operate, or otherwise fails to provide
overpressure protection, the operator must repair or replace the device
or pressure sensing equipment immediately.
    (ii) If a pressure relief device allows gas to release to the
atmosphere at an operating pressure below the set actuation pressure
range, the operator must take immediate and continuous action with on-
site personnel to stop the release until the device is repaired or
replaced. The relief device or pressure sensing equipment must be
repaired or replaced as soon as practicable but within 30 days.
    (b) Each operator must develop, maintain, and follow written
operations and maintenance procedures to ensure that a pressure relief
device configuration, as demonstrated by a documented engineering
analysis, employs set and reset actuation pressures ensuring
minimization of release volumes while providing adequate overpressure
protection.
    (c) Records under this section must be maintained as follows:
    (1) Records of relief devices malfunctions must be maintained for 5
years after repair or replacement.
    (2) Records pertaining to repair, replacement, or reconfiguration
(including any engineering analyses) of a pressure relief device must
be maintained for the life of the pipeline.
0
37. In Sec.  192.1007, revise paragraphs (e)(1)(i) and (v) as follows:

Sec.  192.1007  What are the required elements of an integrity
management plan?

* * * * *
    (e) * * *
    (1) * * *
    (i) Number of hazardous leaks either eliminated or repaired (or
total number of leaks if all leaks are repaired when found),
categorized by cause;
* * * * *
    (v) Number of hazardous leaks either eliminated or repaired (or
total number of leaks if all leaks are repaired when found),
categorized by material; and
* * * * *

PART 193--LIQUEFIED NATURAL GAS FACILITIES: FEDERAL SAFETY
STANDARDS

0
38. The authority citation for part 193 continues to read as follows:

    Authority:  49 U.S.C. 5103, 60102, 60103, 60104, 60108, 60109,
60110, 60113, 60118; and 49 CFR 1.53.

0
39. In Sec.  193.2503, add paragraph (h) to read as follows:

Sec.  193.2503  Operating procedures.

* * * * *
    (h) Eliminating leaks and minimizing releases of gas.
0
40. Add Sec.  193.2523 to read as follows:

Sec.  193.2523  Minimizing emissions from blowdowns and boiloff.

    (a) Except as provided in paragraph (b) of this section, an
operator of an LNG facility must minimize intentional emissions of
natural gas from LNG facilities, including tank boiloff or blowdowns
for repairs, construction, operations, or maintenance. The operator
must minimize the release of natural gas to the environment by use of
one or more of the following methods:
    (1) Isolating a smaller section of the piping segments by use of
valves or the installation of control fittings;
    (2) Routing gas released from the facility to a flare, or to other
equipment for use as fuel gas;
    (3) Transferring gas or LNG to a storage tank or local pressure
vessel; or
    (4) Employing an alternative method demonstrated to result in
release volume reductions of at least 50% compared to venting gas
directly to the atmosphere without mitigative action.
    (b) An operator is not required to comply with the provisions of
paragraph (a) of this section during an emergency resulting in the
activation of their emergency procedures under Sec.  193.2509. An
operator must document each emergency release without mitigation
described in paragraph (b) of this section, including the justification
for release without mitigation.
    (c) The operator must document the method or methods used and
describe how those methods minimize the release of natural gas to the
environment.
0
41. In Sec.  193.2605, add paragraph (b)(3) to read as follows:

Sec.  193.2605  Maintenance procedures.

* * * * *
    (b) * * *
    (3) Procedures for eliminating leaks and minimizing releases of
gas.
* * * * *
0
42. Add Sec.  193.2624 to read as follows:

Sec.  193.2624  Leakage surveys.

    (a) Each operator of an LNG facility, including mobile, temporary,
and satellite facilities must conduct periodic methane leakage surveys,
on equipment and components within their facilities containing methane
or LNG, at least four times each calendar year, with a maximum interval
between surveys not exceeding 4\1/2\ months, using leak detection
equipment. Leak detection equipment must be capable of detecting and
locating all methane leaks producing a reading of 5 parts per million
or more of within 5 feet of the component or equipment surveyed.
    (b) Operators must have written procedures providing for each of
the following:
    (1) Validating the leakage survey equipment and performing leakage
surveys consistent with the equipment manufacturer's instructions for
survey methods and allowable environmental and operational parameters;
    (2) Validating the sensitivity of this equipment by the operator
before initial use by testing with a known concentration of gas at a
required offset condition of 5 feet; and
    (3) Calibrating the equipment consistent with the equipment
manufacturer's instructions for calibration and maintenance. Leak
detection equipment must be recalibrated or replaced following any
indication of malfunction.
    (c) Each operator must maintain records of the leak survey and
equipment sensitivity validation and calibration for five years after
the leakage survey.
    (d) Operators must review the results of the methane leakage
surveys and address any methane leaks and abnormal operating conditions
in accordance with their written maintenance procedures or abnormal
operating procedures.

    Issued in Washington, DC, on May 4, 2023, under authority
delegated in 49 CFR 1.97.
Alan K. Mayberry,
Associate Administrator for Pipeline Safety.
[FR Doc. 2023-09918 Filed 5-17-23; 8:45 am]
BILLING CODE 4910-60-P


[Federal Register Volume 81, Number 183 (Wednesday, September 21, 2016)]
[Notices]
[Pages 64913-64914]
[FR Doc No: 2016-22711]

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DEPARTMENT OF HEALTH AND HUMAN SERVICES

Food and Drug Administration

[Docket No. FDA-2016-D-2561]

Coordinated Development of Antimicrobial Drugs and Antimicrobial
Susceptibility Test Devices; Draft Guidance for Industry and Food and
Drug Administration Staff; Availability

AGENCY: Food and Drug Administration, HHS.

ACTION: Notice of availability.

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

SUMMARY: The Food and Drug Administration (FDA or Agency) is announcing
the availability of a draft guidance entitled ``Coordinated Development
of Antimicrobial Drugs and Antimicrobial Susceptibility Test Devices.''
This draft guidance is intended to assist drug sponsors and device
manufacturers who are planning to develop new antimicrobial drugs and
antimicrobial susceptibility test (AST) devices and who seek to
coordinate development of these products such that the AST device could
be cleared either at the time of new drug approval or shortly
thereafter. This draft guidance is not final nor is it in effect at
this time.

DATES: Although you can comment on any guidance at any time (see 21 CFR
10.115(g)(5)), to ensure that the Agency considers your comment of this
draft guidance before it begins work on the final version of the
guidance, submit either electronic or written comments on the draft
guidance by November 21, 2016.

ADDRESSES: You may submit comments as follows:

Electronic Submissions

    Submit electronic comments in the following way:
     Federal eRulemaking Portal: http://www.regulations.gov.
Follow the instructions for submitting comments. Comments submitted
electronically, including attachments, to http://www.regulations.gov
will be posted to the docket unchanged. Because your comment will be
made public, you are solely responsible for ensuring that your comment
does not include any confidential information that you or a third party
may not wish to be posted, such as medical information, your or anyone
else's Social Security number, or confidential business information,
such as a manufacturing process. Please note that if you include your
name, contact information, or other information that identifies you in
the body of your comments, that information will be posted on http://www.regulations.gov.
     If you want to submit a comment with confidential
information that you do not wish to be made available to the public,
submit the comment as a written/paper submission and in the manner
detailed (see ``Written/Paper Submissions'' and ``Instructions'').

Written/Paper Submissions

    Submit written/paper submissions as follows:
     Mail/Hand delivery/Courier (for written/paper
submissions): Division of Dockets Management (HFA-305), Food and Drug
Administration, 5630 Fishers Lane, Rm. 1061, Rockville, MD 20852.
     For written/paper comments submitted to the Division of
Dockets Management, FDA will post your comment, as well as any
attachments, except for information submitted, marked and identified,
as confidential, if submitted as detailed in ``Instructions.''
    Instructions: All submissions received must include the Docket No.
FDA-2016-D-2561 for ``Coordinated Development of Antimicrobial Drugs
and Antimicrobial Susceptibility Test Devices.'' Received comments will
be placed in the docket and, except for those submitted as
``Confidential Submissions,'' publicly viewable at http://www.regulations.gov or at the Division of Dockets Management between 9
a.m. and 4 p.m., Monday through Friday.
     Confidential Submissions--To submit a comment with
confidential information that you do not wish to be made publicly
available, submit your comments only as a written/paper submission. You
should submit two copies total. One copy will include the information
you claim to be confidential with a heading or cover note that states
``THIS DOCUMENT CONTAINS CONFIDENTIAL INFORMATION.'' The Agency will
review this copy, including the claimed confidential information, in
its consideration of comments. The second copy, which will have the
claimed confidential information redacted/blacked out, will be
available for public viewing and posted on http://www.regulations.gov.
Submit both copies to the Division of Dockets Management. If you do not
wish your name and contact information to be made publicly available,
you can provide this information on the cover sheet and not in the body
of your comments and you must identify this information as
``confidential.'' Any information marked as ``confidential'' will not
be disclosed except in accordance with 21 CFR 10.20 and other
applicable disclosure law. For more information about FDA's posting of

comments to public dockets, see 80 FR 56469, September 18, 2015, or
access the information at: http://www.fda.gov/regulatoryinformation/dockets/default.htm.
    Docket: For access to the docket to read background documents or
the electronic and written/paper comments received, go to http://www.regulations.gov and insert the docket number, found in brackets in
the heading of this document, into the ``Search'' box and follow the
prompts and/or go to the Division of Dockets Management, 5630 Fishers
Lane, Rm. 1061, Rockville, MD 20852.
    An electronic copy of the guidance document is available for
download from the Internet. See the SUPPLEMENTARY INFORMATION section
for information on electronic access to the guidance. Submit written
requests for a single hard copy of the draft guidance document entitled
``Coordinated Development of Antimicrobial Drugs and Antimicrobial
Susceptibility Test Devices'' to the Office of the Center Director,
Guidance and Policy Development, Center for Devices and Radiological
Health, Food and Drug Administration, 10903 New Hampshire Ave., Bldg.
66, Rm. 5431, Silver Spring, MD 20993-0002. Alternatively, you may
submit written requests for single copies of the guidance to the
Division of Drug Information, Center for Drug Evaluation and Research,
Food and Drug Administration, 10903 New Hampshire Ave., Bldg. 51, Rm.
2201, Silver Spring, MD 20993-0002. Send one self-addressed adhesive
label to the office that you are ordering from to assist in processing
your request.

FOR FURTHER INFORMATION CONTACT: Ribhi Shawar, Center for Devices and
Radiological Health, Food and Drug Administration, 10903 New Hampshire
Ave., Bldg. 66, Rm. 4604, Silver Spring, MD 20993-0002,<PHONE_NUMBER>;
or Joseph Toerner, Center for Drug Evaluation and Research, 10903 New
Hampshire Ave., Bldg. 22, Rm. 6244, Silver Spring, MD 20993-0002, 301-
796-1400.

SUPPLEMENTARY INFORMATION:

I. Background

    This guidance, when finalized, is intended to assist drug sponsors
and device manufacturers who are planning to develop new antimicrobial
drugs and AST devices and who seek to coordinate development of these
products such that the AST device could be cleared either at the time
of new drug approval or shortly thereafter.
    Specifically, the guidance intends to describe the interactions
between drug sponsors and device manufacturers for coordinated
development of a new antimicrobial drug and an AST device; explain the
considerations for submitting separate applications to the Center for
Drug Evaluation and Research (CDER) and the Center for Devices and
Radiological Health (CDRH) when seeking clearance of an AST device
coincident with, or soon following, antimicrobial drug approval; and
clarify that the review of the new antimicrobial drug product and AST
device(s) will remain independent, and that coordinated development
does not influence the review timelines for either product.

II. Significance of Guidance

    This draft guidance is being issued consistent with FDA's good
guidance practices regulation (21 CFR 10.115). The draft guidance, when
finalized, will represent the current thinking of FDA on coordinated
development of antimicrobial drugs and antimicrobial susceptibility
test devices. It does not establish any rights for any person and is
not binding on FDA or the public. You can use an alternative approach
if it satisfies the requirements of the applicable statutes and
regulations.

III. Electronic Access

    Persons interested in obtaining a copy of the draft guidance may do
so by downloading an electronic copy from the Internet. A search
capability for all Center for Devices and Radiological Health guidance
documents is available at http://www.fda.gov/MedicalDevices/DeviceRegulationandGuidance/GuidanceDocuments/default.htm, and a search
capability for all Center for Drug Evaluation and Research guidance
documents is available at http://www.fda.gov/Drugs/GuidanceComplianceRegulatoryInformation/Guidances/default.htm. Guidance
documents are also available at http://www.regulations.gov. Persons
unable to download an electronic copy of ``Coordinated Development of
Antimicrobial Drugs and Antimicrobial Susceptibility Test Devices'' may
send an email request to<EMAIL_ADDRESS>to receive an
electronic copy of the document. Please use the document number 1400061
to identify the guidance you are requesting.

IV. Paperwork Reduction Act of 1995

    This draft guidance refers to previously approved collections of
information. These collections of information are subject to review by
the Office of Management and Budget (OMB) under the Paperwork Reduction
Act of 1995 (44 U.S.C. 3501-3520). The collections of information in 21
CFR part 807, subpart E have been approved under OMB control number
0910-0120, the collections of information in 21 CFR part 812 have been
approved under OMB control number 0910-0078, the collections of
information in 21 CFR part 312 have been approved under OMB control
number 0910-0014, and the collections of information in 21 CFR part 314
have been approved under OMB control number 0910-0001. The collections
of information in the guidance document ``Requests for Feedback on
Medical Device Submissions: The Pre-Submission Program and Meetings
with Food and Drug Administration Staff'' have been approved under OMB
control number 0910-0756.

    Dated: September 15, 2016.
Leslie Kux,
Associate Commissioner for Policy.
[FR Doc. 2016-22711 Filed 9-20-16; 8:45 am]
 BILLING CODE 4164-01-P


[Federal Register: June 12, 2006 (Volume 71, Number 112)]
[Notices]
[Page 33731-33732]
[DOCID:fr12jn06-51]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Docket No. RP96-383-078]

Dominion Transmission, Inc.; Notice of Negotiated Rates

June 6, 2006.
    Take notice that on May 31, 2006, Dominion Transmission, Inc. (DTI)
tendered for filing as part of its FERC Gas Tariff, Third Revised
Volume No. 1, the following tariff sheets, to become effective June 1,
2006:

    First Revised Sheet No. 40
    Third Revised Sheet No. 251
    Third Revised Sheet No. 252
    Sixth Revised Sheet No. 1405
    Fourth Revised Sheet No. 1407
    Third Revised Sheet No. 1408
    Fourth Revised Sheet No. 1414
    Third Revised Sheet No. 1415

    DTI states that the purpose of this filing is to report new
negotiated transactions, amend various negotiated rate transactions and
to correct typographical errors on two tariff sheets.
    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. Such notices,
motions, or protests must be filed in accordance with the provisions of
Section 154.210 of the Commission's regulations (18 CFR 154.210).
Anyone filing an intervention

or protest must serve a copy of that document on the Applicant. Anyone
filing an intervention or protest on or before the intervention or
protest date need not serve motions to intervene or protests on persons
other than the Applicant.
    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 14 copies of the protest or intervention to the Federal
Energy Regulatory Commission, 888 First Street, NE., Washington, DC
20426.
    This filing is accessible online 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 Web site that enables subscribers to receive e-mail
notification when a document is added to a subscribed docket(s). For
assistance with any FERC Online service, please e-mail
<EMAIL_ADDRESS>or call<PHONE_NUMBER> (toll free). For

TTY, call<PHONE_NUMBER>.

Magalie R. Salas,
Secretary.
[FR Doc. E6-9118 Filed 6-9-06; 8:45 am]

BILLING CODE 6717-01-P


[Federal Register Volume 81, Number 213 (Thursday, November 3, 2016)]
[Notices]
[Pages 76582-76583]
[FR Doc No: 2016-26617]

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ENVIRONMENTAL PROTECTION AGENCY

[EPA-HQ-OGC-2016-0623; FRL-9954-93-OGC]

Proposed Consent Decree, Clean Air Act Citizen Suit

AGENCY: Environmental Protection Agency (EPA).

ACTION: Notice of proposed consent decree; request for public comment.

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

SUMMARY: In accordance with section 113(g) of the Clean Air Act, as
amended (``CAA'' or the ``Act''), notice is hereby given of a proposed
consent decree to address a lawsuit filed by Citizens for Clean Air and
Sierra Club (``Plaintiffs'') in the United States District Court for
the Western District of Washington: Citizens for Clean Air, et al. v.
McCarthy, et al. No. 2:16-cv-00857-JCC (W.D. WA.). On June 14, 2016,
Plaintiffs filed a lawsuit alleging that Gina McCarthy, in her official
capacity as Administrator of the United States Environmental Protection
Agency (``EPA'') and Dennis McLerran, in his official capacity as
Regional Administrator of the United States Environmental Protection
Agency, Region 10 (collectively, ``EPA''), failed to perform duties
mandated by CAA to take final action to approve, disapprove, or
conditionally approve, in whole or in part, the Fairbanks North Star
Borough Moderate Area Attainment Plan for attainment of the 2006 24-
hour fine particulate matter (``PM2.5'') NAAQS, which Alaska
submitted to EPA in two parts on December 31, 2014 and January 29,
2015. The proposed consent decree would establish deadlines for EPA to
take certain specified actions related to the Alaska submissions.

DATES: Written comments on the proposed consent decree must be received
by December 5, 2016.

ADDRESSES: Submit your comments, identified by Docket ID number EPA-HQ-
OGC-2016-0623, online at www.regulations.gov. For comments submitted at
www.regulations.gov, follow the online instructions for submitting
comments. Once submitted, comments cannot be edited or removed from
www.regulations.gov. The EPA

may publish any comment received to its public docket. Do not submit
electronically any information you consider to be Confidential Business
Information (CBI) or other information whose disclosure is restricted
by statute. Multimedia submissions (audio, video, etc.) must be
accompanied by a written comment. The written comment is considered the
official comment and should include discussion of all points you wish
to make. The EPA generally will not consider comments or comment
contents located outside of the primary submission (i.e. on the web,
cloud, or other file sharing system). For additional submission
methods, please contact the person identified in the ``For Further
Information Contact'' section. For the full EPA public comment policy,
information about CBI or multimedia submissions, and general guidance
on making effective comments, please visit http://www2.epa.gov/dockets/commenting-epa-dockets.

FOR FURTHER INFORMATION CONTACT: Geoffrey L. Wilcox, Air and Radiation
Law Office (2344A), Office of General Counsel, U.S. Environmental
Protection Agency, 1200 Pennsylvania Ave. NW., Washington, DC 20460;
telephone:<PHONE_NUMBER>; fax number:<PHONE_NUMBER>; email address:
<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION:

I. Additional Information About the Proposed Consent Decree

    On June 14, 2016, Plaintiffs filed a lawsuit alleging that EPA has
a mandatory duty to take final action to approve, disapprove, or
conditionally approve, in whole or in part, the Fairbanks North Star
Borough Moderate Area Attainment Plan for the 2006 24-hour
PM2.5 NAAQS. Alaska made this SIP submission to EPA in two
parts on December 31, 2014 and January 29, 2015. EPA found the
submission complete pursuant to CAA section 110(k)(1)(B), 42 U.S.C.
7410(k)(1)(B), on February 18, 2015. Section 110(k)(2) requires EPA to
take action on a SIP submission within one year of the date it is
complete.
    The proposed consent decree would resolve a lawsuit filed by the
Plaintiffs seeking to compel EPA to take actions required under CAA
section 110(k)(2)-(4) with respect to the Fairbanks North Star Borough
Moderate Area Attainment Plan. Under the terms of the proposed consent
decree, EPA must take proposed action on the SIP submission no later
than January 19, 2017, and must take final action thereon no later than
August 28, 2017. See the proposed consent decree for the specific
details.
    For a period of thirty (30) days following the date of publication
of this notice, the Agency will accept written comments relating to the
proposed consent decree from persons who are not named as parties or
intervenors to the litigation in question. EPA or the Department of
Justice may withdraw or withhold consent to the proposed consent decree
if the comments disclose facts or considerations that indicate that
such consent is inappropriate, improper, inadequate, or inconsistent
with the requirements of the Act. Unless EPA or the Department of
Justice determines that consent to this proposed consent decree should
be withdrawn, the terms of the consent decree will be affirmed.

II. Additional Information About Commenting on the Proposed Consent
Decree

A. How can I get a copy of the proposed consent decree?

    The official public docket for this action (identified by EPA-HQ-
OGC-2016-0623) contains a copy of the proposed consent decree. The
official public docket is available for public viewing at the Office of
Environmental Information (OEI) Docket in the EPA Docket Center, EPA
West, Room 3334, 1301 Constitution Ave. NW., Washington, DC. The EPA
Docket Center Public Reading Room is open from 8:30 a.m. to 4:30 p.m.,
Monday through Friday, excluding legal holidays. The telephone number
for the Public Reading Room is<PHONE_NUMBER>, and the telephone number
for the OEI Docket is<PHONE_NUMBER>.
    An electronic version of the public docket is available through
www.regulations.gov. You may use www.regulations.gov to submit or view
public comments, access the index listing of the contents of the
official public docket, and access those documents in the public docket
that are available electronically. Once in the system, key in the
appropriate docket identification number then select ``search''.
    It is important to note that EPA's policy is that public comments,
whether submitted electronically or in paper, will be made available
for public viewing online at www.regulations.gov without change, unless
the comment contains copyrighted material, CBI, or other information
whose disclosure is restricted by statute. Information claimed as CBI
and other information whose disclosure is restricted by statute is not
included in the official public docket or in the electronic public
docket. EPA's policy is that copyrighted material, including
copyrighted material contained in a public comment, will not be placed
in EPA's electronic public docket but will be available only in
printed, paper form in the official public docket. Although not all
docket materials may be available electronically, you may still access
any of the publicly available docket materials through the EPA Docket
Center.

B. How and to whom do I submit comments?

    You may submit comments as provided in the ADDRESSES section.
Please ensure that your comments are submitted within the specified
comment period. Comments received after the close of the comment period
will be marked ``late.'' EPA is not required to consider these late
comments.
    If you submit an electronic comment, EPA recommends that you
include your name, mailing address, and an email address or other
contact information in the body of your comment and with any disk or CD
ROM you submit. This ensures that you can be identified as the
submitter of the comment and allows EPA to contact you in case EPA
cannot read your comment due to technical difficulties or needs further
information on the substance of your comment. Any identifying or
contact information provided in the body of a comment will be included
as part of the comment that is placed in the official public docket,
and made available in EPA's electronic public docket. If EPA cannot
read your comment due to technical difficulties and cannot contact you
for clarification, EPA may not be able to consider your comment.
    Use of the www.regulations.gov Web site to submit comments to EPA
electronically is EPA's preferred method for receiving comments. The
electronic public docket system is an ``anonymous access'' system,
which means EPA will not know your identity, email address, or other
contact information unless you provide it in the body of your comment.
In contrast to EPA's electronic public docket, EPA's electronic mail
(email) system is not an ``anonymous access'' system. If you send an
email comment directly to the Docket without going through
www.regulations.gov, your email address is automatically captured and
included as part of the comment that is placed in the official public
docket, and made available in EPA's electronic public docket.

Gautam Srinivasan,
Deputy Associate General Counsel.
[FR Doc. 2016-26617 Filed 11-2-16; 8:45 am]
 BILLING CODE 6560-50-P