addition, it is not certain during the drilling operations whether a
well will be a producing well. Hence, it is not known whether an oil
and natural gas production facility will be constructed to support that
well. The outcome of a completion operation provides the well owners
and operators information necessary to determine whether an oil and
natural gas production facility will be constructed.
    Clarification: We have added language to the introduction at Sec.
49.4161(b) to clarify that, for the purposes of this rule, the
initiation of well completion operations and well recompletion
operations are the dates that construction and modifications commence,
as set forth in the regulatory text of this final rule.
    Compliance with the rule is required no later than June 20, 2013 or
upon initiation of well completion or recompletion operations,
whichever is later. Upon signature by the Administrator, we will post
this rule on our internet site (http://www.epa.gov/region8/air/fbirfip.html) and notify the owners and operators and the Three
Affiliated Tribes of the Mandan, Hidatsa, and Arikara Nation.
    Clarification: We have changed the language in the introduction at
Sec.  49.4161(c) to clarify that the compliance date is upon initiation
of well completion operations and well recompletion operations, as
follows: ``Sec.  49.4161(c) When must I comply with Sec. Sec.  49.4161
through 49.4168? Compliance with Sec. Sec.  49.4161 through 49.4168 is
required no later than June 20, 2013 or upon initiation of well
completion operations or well recompletion operations, whichever is
later.''

C. Provisions for Delegation of Administration to the Three Affiliated
Tribes of the Mandan, Hidatsa, and Arikara Nation

    The provisions in Sec.  49.4162 establish the steps by which the
Three Affiliated Tribes of the Mandan, Hidatsa, and Arikara Nation may
request delegation to assist us with the administration of this rule
and the process by which the Regional Administrator of the EPA Region 8
may delegate to the Tribes the authority to assist with such
administration of this rule. As described in the regulatory provisions,
any such delegation will be accomplished through a delegation of
authority agreement between the Regional Administrator and the Three
Affiliated Tribes of the Mandan, Hidatsa, and Arikara Nation. This
section provides for administrative delegation of this federal rule and
does not affect the eligibility criteria under CAA section 301(d) and
40 CFR 49.6 for TAS should the Tribes decide to seek such treatment for
the purpose of administering their own EPA-approved program under
tribal law. Administrative delegation is a separate process from TAS
under the TAR. Under the TAR, Indian tribes seek EPA-approval of their
eligibility to run CAA programs under their own laws. The Three
Affiliated Tribes of the Mandan, Hidatsa, and Arikara Nation would not
need to seek TAS under the TAR for purposes of requesting to assist us
with administration of this rule through a delegation of authority
agreement. In the event such an agreement is reached, the rule would
continue to operate under federal authority throughout the FBIR, and
the Tribes would assist us with administration of the rule to the
extent specified in the agreement.

D. General Provisions

    The provisions in Sec.  49.4163 General Provisions provide: (1)
Definitions that apply to this rule; (2) assurance that we will
maintain its authority to require testing, monitoring, recordkeeping,
and reporting in addition to that already required by an applicable
requirement, in a permit to construct or permit to operate in order to
ensure compliance; and (3) assurance that nothing in the rule will
preclude the use, including the exclusive use, of any credible evidence
or information, relevant to whether a facility would have been in
compliance with applicable requirements if the appropriate performance
or compliance test had been performed.

E. Construction and Operational Control Measures

    The provisions in Sec.  49.4164 Construction and Operational
Control Measures provide requirements to reduce VOC emissions during
well completion and recompletion operations. The owner or operator must
route all casinghead natural gas emissions associated with completion
and recompletion operations to a utility flare or a pit flare capable
of reducing the mass content of VOCs in the natural gas vented to it by
at least 90.0%. We note that the well completion and recompletion
control requirements to use pit flares or utility flares that have the
capability to reduce the mass content of VOC in the natural gas
emissions routed to them by at least 90.0% percent by weight are the
minimum level of control that will be allowed under this rule. Owners
and operators may also choose to perform reduced emission completions
and recompletions \32\, which would exceed the 90.0% VOC emission
reduction requirement. This section also requires the control of
production and storage operations and imposes a timeline for
installation of the controls on these operations. The owner or operator
is required to reduce the mass content of VOC emissions from natural
gas during oil and natural gas production and storage operations by at
least 90.0% percent on the first date of production.
---------------------------------------------------------------------------

    \32\ U.S. Environmental Protection Agency. Lessons Learned from
Natural Gas STAR Partners: Reduced Emissions Completions for
Hydraulically Fractured Natural Gas Wells. Office of Air and
Radiation: Natural Gas Star Program. Washington, DC. Available at:
http://epa.gov/gasstar/documents/reduced_emissions_completions.pdf. Accessed July 26, 2012. A copy of this document has
been placed in the docket for this rule under Docket ID: EPA-R08-
OAR-2012-0479, which can be accessed at: http://www.regulations.gov.
---------------------------------------------------------------------------

    Within 90 days of the first date of production, we require the
owner or operator to route the natural gas from the production and
storage operations through a closed-vent system to a utility flare or
equivalent combustion device capable of reducing the mass content of
VOC in the natural gas vented to the device by at least 98.0%. The
owner or operator also has the option to design their production and
storage operations to recover the natural gas as product and inject it
into a natural gas gathering pipeline system for sale or other
beneficial purpose. For those owners or operators that choose to
capture the natural gas as product rather than a pollutant to be
controlled, the natural gas may temporarily be routed through a closed-
vent system to an enclosed combustor, utility flare or pit flare in
instances where injection of the product into the pipeline is
temporarily infeasible. In these situations, the pit flare is
considered a backup standby unit used for unplanned flare events, such
as during temporarily limited pipeline capacity, that are beyond a
producer's control and the pit flare is used to safely burn the natural
gas product that could otherwise pose a potential risk to workers, the
community, or the environment. The owner or operator, however, must
limit the use of the pit flare in these instances to 500 hours in any
consecutive 12-month period.
    The rule requires the owner or operator to route all standing,
working, breathing and flashing losses from the produced oil storage
tanks and any produced water storage tanks interconnected with the
produced oil storage tanks through a closed vent system to either an
operating system

designed to recover and inject the natural gas emissions into a natural
gas gathering pipeline system for sale or other beneficial use, or to
an enclosed combustor or utility flare capable of reducing the mass
content of VOC in the natural gas emissions vented to the device by at
least 98.0%. However, to prevent duplicative federal requirements for
owners and operators of storage tanks on the FBIR subject to both this
rule and NSPS OOOO, storage tanks subject to and controlled under the
requirements specified in 40 CFR part 60, subpart OOOO are considered
to meet the storage tank control requirements of this rule. No further
requirements apply for such storage tanks under this rule. In addition,
the rule provides that if the uncontrolled PTE of VOCs from the
aggregate of all produced oil storage tanks and produced water storage
tanks interconnected with produced oil storage tanks at an oil and
natural gas production facility is less than, and reasonably expected
to remain below, 20 tons in any consecutive 12-month period, then the
owner or operator may use a utility flare or enclosed combustor that is
capable of reducing the mass content of VOC in the natural gas
emissions vented to the device by only 90.0% upon prior written
approval by the EPA.\33\
---------------------------------------------------------------------------

    \33\ If the owner or operator receives written approval for a
new method from the EPA, the owner or operator must calculate
potential to emit based on the new EPA-approved method.
---------------------------------------------------------------------------

    The control devices must be operated under specific conditions as
specified in Sec.  49.4165 Control Equipment Requirements and Sec.
49.4166 Monitoring Requirements.

F. Control Equipment Requirements

    The provisions in Sec.  49.4165 Control Equipment Requirements
require the use of covers on all produced oil and water storage tanks
and the use of closed-vent systems with all VOC capture and control
equipment. Section 49.4165 also specifies construction and operational
requirements for the covers and closed-vent systems. In addition, Sec.
49.4165 requires specific construction and operational requirements of
pit flares, enclosed combustors, and utility flares.
    The provisions in Sec.  49.4165 require that each owner and
operator equip the openings on each produced oil storage tank and each
produced water storage tank that is interconnected with produced oil
storage tanks with a cover that ensures that natural gas emissions are
efficiently routed through a closed-vent system to a vapor recovery
system an enclosed combustor, or a utility flare. Each cover and all
openings on the cover (e.g., access hatches, sampling ports, and gauge
wells) must form a continuous barrier over the entire surface area of
the produced oil and produced water in the storage tank. Each cover
opening must be secured in a closed, sealed position (e.g., covered by
a gasketed lid or cap) whenever material is in the tank on which the
cover is installed except during those times when it is necessary to
use an opening as follows: (1) To add material to, or remove material
from the unit (this includes openings necessary to equalize or balance
the internal pressure of the unit following changes in the level of the
material in the unit); or (2) to inspect or sample the material in the
unit; or to inspect, maintain, repair, or replace equipment located
inside the unit.
    Each owner and operator is required to use closed-vent systems to
collect and route natural gas emissions to the respective VOC control
devices. All vent lines, connections, fittings, valves, relief valves,
or any other appurtenance employed to contain and collect gases, and
transport them to the VOC control equipment must be maintained and
operated properly during any time the control equipment is operating
and must be designed to operate with no detectable natural gas
emissions. If a closed-vent system contains one or more bypass devices
that could be used to divert all or a portion of the natural gas from
entering the VOC control devices, the owner or operator must meet one
of the following options for each bypass device: (1) At the inlet to
the bypass device properly install, calibrate, maintain, and operate a
natural gas flow indicator capable of taking periodic readings and
sounding an alarm when the bypass device is open such that the natural
gas is being, or could be, diverted away from the control device and
into the atmosphere; or (2) secure the bypass device valve in the non-
diverting position using a car-seal or a lock-and-key type
configuration.
    Each owner or operator is required to follow the manufacturer's
written operating instructions, procedures and maintenance schedule to
ensure good air pollution control practices for minimizing emissions
from each enclosed combustor or utility flare. Each enclosed combustor
must have the capacity to reduce the mass content of the VOC in the
natural gas routed to it by at least 98.0% for the minimum and maximum
natural gas volumetric flow rate and British Thermal Unit (BTU) content
routed to it. For the purposes of this rule, we require that all
utility flares installed per this rule meet the requirements in 40 CFR
60.18(b), and all enclosed combustors installed per this rule must be
tested according to the NSPS OOOO performance testing requirements.
Until such time that compliance is required with the storage vessel
requirements in the NSPS OOOO standard, however, the owner or operators
can demonstrate compliance using methods specified in this rule.
    We determined that certain work practice and operational
requirements are also necessary for the practical enforceability of the
VOC emission reduction requirement that the enclosed combustors or
utility flares must achieve. Flares and combustors must be operated
within specific parameters to effectively destroy VOC emissions.
Therefore, each owner or operator must ensure that each enclosed
combustor or utility flare is: (1) Operated at all times that produced
natural gas and natural gas emissions are routed to it; (2) operated
with a liquid knock-out system to collect any condensable vapors (to
prevent liquids from going through the control device); (3) equipped
with a flash-back flame arrestor; (4) equipped with a continuous
burning pilot flame or an electronically controlled electronically
controlled automatic igniter system; (5) equipped with a monitoring
system for continuous recording of the parameters that indicate proper
operation of each enclosed combustor, utility flare, continuous burning
pilot flame and electronically controlled automatic igniter, such as a
chart recorder, data logger, or similar devices; (6) maintained in a
leak free condition; and (7) operated with no visible smoke emissions.
    Section 49.4165 requires that each owner or operator limit the use
of pit flares to: (1) The control natural gas emissions during well
completion operations; (2) the control of VOC emissions in the event
the natural gas that is being recovered for sale or other beneficial
purpose must be diverted to a backup control device because injection
into the pipeline is temporarily infeasible and there is no operational
enclosed combustor or utility flare at the oil and natural gas
production facility, in which instances the owner or operator must
limit use of the pit flare to no more than 500 hours in any consecutive
12-month period; or (3) use when total uncontrolled PTE of VOCs from
all produced oil storage tanks and any produced water storage tanks
interconnected with produced oil storage tanks at an oil and natural
gas production facility have declined to less than, and are reasonably
expected to stay below, 20 tons in any consecutive

12-month period. Each pit flare must be operated to reduce the mass
content of VOC in the natural gas routed to it by at least 90.0% and
must be operated with no visible smoke emissions. Each pit flare must
be equipped with an electronically controlled automatic igniter with
malfunction alarm and remote notification system if the pilot flame
fails. Each pit flare must be visually inspected for the presence of a
pilot flame any time natural gas is being routed to it and if the pilot
flame fails, it must be relit as soon as safely possible and the
electronically controlled automatic igniter must be repaired or
replaced before the pit flare is used again.
    Section 49.4165 allows owners or operators of oil and natural gas
production facilities to use control devices other than an enclosed
combustor or utility flare, provided they are capable of achieving at
least a 98.0% VOC destruction efficiency and upon our prior written
approval by the EPA. This provision will allow for owner or operators
to take advantage of technological advances in VOC emission control for
the oil and natural gas production industry and will provide us with
valuable information on any new control technologies.
    Deletion: We have deleted the testing requirement at Sec.
49.4165(c)(5)(iii). This was a temporary enclosed combustor testing
requirement that applied until 40 CFR part 60 subpart OOOO-New Source
Performance Standard for Oil and Natural Gas Sector (NSPS OOOO) was
promulgated. Since NSPS OOOO was promulgated on August 16, 2012 and
became effective on October 15, 2012, this temporary provision is no
longer necessary.
    Correction: We have clarified control equipment requirements at
Sec.  49.4165(c)(4). We have added language at Sec.  49.4165(c)(4) to
provide an exemption to Sec.  60.18(c)(2) and (f)(2) for those utility
flares operated with an electronically controlled automatic igniter as
set forth in the regulatory text of this final rule.
    Clarification: We have clarified that enclosed combustors and
utility flares must be operated properly at all times that produced
natural gas and/or natural gas emissions are routed to them, rather
than just the term natural gas. The rule now reads as set forth in the
regulatory text of this final rule at Sec.  49.4165(c)(6)(i).
    Correction: We have removed the requirement to install equipment
for the monitoring of continuous burning pilot flames and
electronically controlled automatic igniters on flares and combustors.
These requirements were already provided for at Sec.  49.4166(g)(1).
The rule now reads as set forth in the regulatory text of this final
rule at Sec.  49.4165(c)(6)(iv).
    Clarification: We have clarified the purpose for equipping utility
flares and enclosed combustors with a monitoring system. We have
revised the applicable provisions to read as set forth in the
regulatory text of this final rule at Sec.  49.4165(c)(6)(v).
    Correction: We removed the requirement to monitor a pilot flame on
pit flares since these flares are to be operated with electronically
controlled automatic igniters only. The rule now reads as set forth in
the regulatory text of this final rule at Sec.  49.4165((d)(3(iv) and
(v).

G. Monitoring Requirements

    Section 49.4166 Monitoring Requirements requires each owner or
operator conduct certain monitoring that we determined is necessary for
the practical enforceability of the VOC emission reduction
requirements, including but not limited to: (1) Monitoring of the
number of barrels of oil produced at the facility each time the oil is
unloaded from the produced oil storage tanks; (2) Monitoring of the
hours of operation of each pit flare used to control VOC emissions in
the event the natural gas that is being recovered for sale or other
beneficial purpose must be diverted to a backup control device because
injection into the pipeline is temporarily infeasible and there is no
operational enclosed combustor or utility flare is at the oil and
natural gas production facility; (3) Monitoring of the volume of
produced natural gas from the heater-treater sent to each enclosed
combustor, utility flare, and pit flare at all times; (4) Monitoring of
the volume of standing, working, breathing, and flashing losses from
the produced oil and produced water storage tanks sent to each vapor
recovery system, enclosed combustor, utility flare, and pit flare at
all times; (5) Visually inspecting storage tank thief hatches, covers,
seals, PRVs, and closed-vent systems to insure proper condition and
functioning; (6) Directly and continuously measuring, various
parameters (i.e., product throughput, enclosed combustor flame
presence, temperature, etc.) related to the proper operation of
emissions units and required control devices to assure compliance with
the emissions reduction requirements and operational limitations; and
(7) Visually inspect all equipment associated with each enclosed
combustor, utility flare, and pit flare at a minimum quarterly to
ensure system integrity; (8) Visually monitoring for visible smoke from
enclosed combustors, utility flares, and pit flares during operation.
    The monitoring, recordkeeping and reporting requirements for the
covers, close-vent systems, pit flares, enclosed combustors, and
utility flares are intended to provide legal and practicable
enforceability of the emission control requirements.
    Correction: We have added monitoring requirements at Sec.
49.4166(d) to describe acceptable gas volume measurement methods, thus
making this provision consistent with the provision at Sec.
49.4166(c). The rule now reads as set forth in the regulatory text of
this final rule.
    Revision: We have included more flexibility in the options for
monitoring approaches. We have revised the applicable provisions to
read as set forth in the regulatory text of this final rule at Sec.
49.4166(g)(1).
    Revision: We have clarified the intent of the provision at Sec.
49.4166(g)(2) in the final FIP to read as set forth in the regulatory
text of this final rule:
    Revision: We have revised the smoke monitoring provisions at Sec.
49.4166(g)(3) in the final FIP to read as set forth in the regulatory
text of this final rule.
    Revision: We have added a new monitoring provision at Sec.
49.4166(i) to allow for other monitoring options upon prior written
approval by the EPA, as set forth in the regulatory text of this final
rule.

H. Recordkeeping Requirements

    Section 49.4167 Recordkeeping Requirements requires that each owner
or operator of an oil and natural gas production facility keep specific
records to be made available upon our request, in lieu of voluminous
reporting requirements. The records that must be kept include, but are
not limited to, all required measurements, monitoring, and deviations
or exceedances of rule requirements and corrective actions taken, as
well as any manufacturer specifications and guarantees or engineering
analyses. These recordkeeping requirements provide legal and practical
enforceability to the control and emission reduction requirements of
this rule.
    Clarification: We have clarified the recordkeeping requirements at
Sec.  49.4167(a)(4)(ii) to correctly identify that casing head gas
vented from producing wells should be monitored, not produced natural
gas. The rule now reads as set forth in the regulatory text of this
final rule.
    Revision: We have revised the recordkeeping requirements at Sec.
49.4167(a)(8) to clarify that records

must be maintained of the volume of natural gas emissions released when
close-vent systems and control devices have been bypassed or were not
operating. The rule now reads as set forth in the regulatory text of
this final rule.
    Correction: We have corrected the recordkeeping requirements at
49.4167(a)(5)(iv) to include the requirement to keep records of any
instance in which an electronically controlled automatic igniter has
failed. The rule now reads as set forth in the regulatory text of this
final rule.

I. Reporting Requirements

    Section 49.4168 Notification and Reporting Requirements requires
that each owner or operator of an oil and natural gas production
facility prepare and submit an annual report, beginning one year after
this rule becomes effective covering the period for the previous
calendar year. The report must include a summary of required records
identifying each oil and natural gas production well completion or
recompletion operation for each facility conducted during the reporting
period, an identification of the first date of production for each oil
and natural gas production well at each facility that commenced
operation during the reporting period, and a summary of deviations or
exceedances of any requirements of this FIP and the corrective measures
taken. Additionally, a report must be submitted for any performance
test we require.
    Clarification: Upon further review of the language at Sec.
49.4168(b) regarding annual reporting requirements, we determined it
was necessary to clarify the requirement based on our original intent.
The provision now reads as set forth in the regulatory text of this
final rule:
    We decided not to require owners or operators to register their oil
and natural gas production facilities, because the Federal Tribal NSR
Rule at 40 CFR 49.151 already requires registration of existing minor
sources and such a requirement in this rule would be redundant.
    These reporting requirements are part of providing legal and
practical enforceability to the control and emission reduction
requirements of this rule.
    Revision: As explained in the response to comments above, we have
added a provision for notification and reporting requirements at Sec.
49.4168(b)(4)(iv) requiring owners or operators to certify as to the
truth, accuracy and completeness of the annual reports. The new
provision is consistent with the NSPS OOOO (40 CFR 60.5420(b)(1)(iv))
and reads as set forth in the regulatory text of this final rule.

J. Effect on Permitting of Facilities

    This rule is not a permitting program. It does not impose or exempt
the facilities from any federal CAA permitting requirements, including
the PSD preconstruction permitting requirements at 40 CFR 52.21,
Federal Tribal NSR Rule permitting requirements for minor sources at 40
CFR 49.151, or federal Title V operating permit requirements at 40 CFR
part 71. The primary purpose of this rule is to address potential
impacts to the public health and the environment. However, the rule
does provide legal and practical enforceability for the use of VOC
emission controls that are already being used voluntarily by the
industry and for VOC emissions reductions from those controls. Provided
that the facilities are in compliance with the new rule, they may take
into account the enforceable VOC emission reductions from the required
controls they use when calculating their PTE for determining
applicability of the federal permitting requirements, to the extent
that the effect those controls would have on VOC emissions is legally
and practicably enforceable.
    Regardless of this rule, due to the high amount of associated
natural gas in the crude oil and the absence of infrastructure to
collect the natural gas on the FBIR, some FBIR facilities' PTE of VOCs
or any other pollutant subject to regulation may exceed the
applicability thresholds for PSD, Federal Tribal NSR Rule, or Title V
permitting even after accounting for the legally and practicably
enforceable emission reductions provided in this rule. In such cases,
the owners or operators of these facilities are required to apply for
and obtain the appropriate permits in accordance with the regulation.

K. Registration Requirements

    This rule does not exempt facilities located on the FBIR from the
registration requirements of the Federal Tribal NSR Rule, promulgated
on July 1, 2011. Nor does this rule impose any additional registration
requirements. The primary purpose of this rule is to address potential
impacts to the public health and the environment. Provided that the
facilities are in compliance with the provisions of this rule,
facilities may include the enforceable VOC emission reductions
resulting from the controls required in this rule when calculating
their PTE, to the extent that the effect those controls would have on
VOC emissions is legally and practicably enforceable.
    If the PTE VOCs or any other regulated NSR pollutant is less than
the major source thresholds in 40 CFR 52.21, but equal to or greater
than the thresholds in the Federal Tribal NSR Rule, then registration
is required of these facilities (40 CFR 49.160). Those facilities that
must obtain a PSD permit pursuant to 40 CFR 52.21 or wish to obtain a
preconstruction permit pursuant to 40 CFR 49.151 of the Federal Tribal
NSR Rule, in addition to meeting the requirements of this rule, are
exempt from this registration requirement.

VII. Statutory and Executive Order

A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review

    This action is not a ``significant regulatory action'' under the
terms of Executive Order 12866 (58 FR 51735, October 4, 1993) and is
therefore not subject to review under Executive Orders 12866 and 13563
(76 FR 3821, January 21, 2011).

B. Paperwork Reduction Act

    The information collection requirements in this rule have been
submitted for approval to the Office of Management and Budget (OMB)
under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. An
Information Collection Request (ICR) document has been prepared by us,
and a copy is available in the docket for this action. The information
collection requirements are not enforceable until OMB approves them.
The ICR document prepared by us has been assigned the EPA ICR tracking
number 2478.01.
    The information requirements are based on notification,
recordkeeping and reporting requirements in this FIP (40 CFR part 49,
subpart K). These requirements are mandatory for each owner or operator
(1) Located on the Fort Berthold Indian Reservation; (2) constructing
or operating an oil or natural gas production facility producing from
the Bakken Pool with one or more oil and natural gas wells and (3) for
which completion or recompletion operations are/were performed on or
after August 12, 2007. See 40 CFR 49.4161. These records and reports
are necessary for the EPA Administrator (or the tribal agency if
delegated), for example, to: (1) Confirm compliance status of
stationary sources; (2) identify any stationary sources not subject to
the requirements and identify

stationary sources subject to the regulations; and (3) ensure that the
stationary source control requirements are being achieved. The
information would be used by the EPA or tribal enforcement personnel
to: (1) Indentify stationary sources subject to the rules; (2) ensure
that appropriate control technology is being properly applied; and (3)
ensure that the emission control devices are being properly operated
and maintained on a continuous basis. Based on the reported
information, the EPA Administrator (or the delegated tribe) can decide
which stationary sources, records or processes should be inspected.
    Specifically, this FIP requires that each owner or operator conduct
certain monitoring that we determined is necessary for the practical
enforceability of the VOC emission reduction requirements. See 40 CFR
49.4166. The recordkeeping requirements in 40 CFR 49.4167 require that
each owner or operator keep specific records to be made available at
the EPA's request. The recordkeeping requirements require only the
specific information needed to determine compliance. Finally, the rules
contain reporting requirements in 40 CFR 49.4168 that require each
owner or operator to prepare and submit an annual report. These
recordkeeping and reporting requirements are specifically authorized by
CAA section 114 (42 U.S.C. 7414). We believe these information
collection requirements are appropriate because they will enable us to
develop and maintain accurate records of air pollution sources and
their emissions, will provide the necessary legal and practical
enforceability, and will ensure appropriate records are available to
verify compliance with this FIP. All information submitted to us
pursuant to the recordkeeping and reporting requirements for which a
claim of confidentiality is made is safeguarded according to the Agency
policies set forth in 40 CFR part 2, subpart B.
    It is estimated that 780 oil and natural gas production facilities
will be subject to this FIP over the next three years. The oil and
natural gas production facilities subject to this rule will incur
approximately 29,655 hours in annual monitoring, reporting, and
recordkeeping burden (averaged over the first three years after the
effective date of the rule), incurring an estimated $6.5 million
($2012) in burden. This includes an annual average of 29,655 labor
hours per year at a total labor cost of $1.4 million per year, average
annualized capital costs of $2.2 million per year, average annual
operating and maintenance costs of $2.9 million per year, and an
average annual estimate of 623 likely respondents over the next three
years. This estimate includes the testing requirements, emission
reports, developing a monitoring plan, notifications and recordkeeping.
All burden estimates are in 2012 calendar year dollars and represent
the most cost-effective monitoring approach for affected facilities.
Burden is defined at 5 CFR 1320.3(b).
    An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for our
regulations in 40 CFR are listed in 40 CFR part 9. When this ICR is
approved by OMB, we will publish a technical amendment to 40 CFR part 9
in the Federal Register to display the OMB control number for the
approved information collection requirements contained in this final
rule.
    To assist members of the public who would like to provide comments
on the ICR, our need for this information, the accuracy of the provided
burden estimates, and any suggested methods for minimizing respondent
burden, we established a public docket for this rule, which includes
this ICR, under Docket ID: EPA-R08-OAR-2012-0479. Submit any comments
related to the ICR to the EPA and OMB. See ADDRESSES section at the
beginning of this notice for information on submitting comments to the
EPA. Send comments to OMB at the Office of Information and Regulatory
Affairs, Office of Management and Budget, 725 17th Street NW.,
Washington, DC 20503, Attention: Desk Office for EPA. Since OMB is
required to make a decision concerning the ICR between 30 and 60 days
after March 22, 2013, please attempt to send comments to OMB by April
22, 2013. Before finalizing the information collection requirements, we
will respond to any comments submitted to the EPA or OMB.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements under the Administrative
Procedure Act or any other statute unless the agency certifies that the
rule will not have a significant economic impact on a substantial
number of small entities. Small entities include small businesses,
small organizations, and small governmental jurisdictions.
    For purposes of assessing the impacts of this rule on small
entities, small entity is defined as: (1) A small business as defined
by the Small Business Administration's (SBA) regulations at 13 CFR
121.201; (2) a small governmental jurisdiction that is a government of
a city, county, town, school district or special district with a
population of less than 50,000; and (3) a small organization that is
any not-for-profit enterprise which is independently owned and operated
and is not dominant in its field.
    After considering the economic impacts of this final rule on small
entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities. In
determining whether a rule has a significant economic impact on a
substantial number of small entities, the impact of concern is any
significant adverse economic impact on small entities, since the
primary purpose of the regulatory flexibility analyses is to identify
and address regulatory alternatives ``which minimize any significant
economic impact of the rule on small entities'' (5 U.S.C. 603 and 604).
Thus, an agency may certify that a rule will not have a significant
economic impact on a substantial number of small entities if the rule
relieves regulatory burden, or otherwise has a positive economic effect
on all of the small entities subject to the rule.
    This rule will not have a significant economic impact on a
substantial number of small entities due to the reduced regulatory
requirement, and thus the regulatory burden, to obtain federal CAA
permits that this rule provides.

D. Unfunded Mandates Reform Act (UMRA)

    This rule does not contain a Federal mandate that may result in
expenditures of $100 million or more for State, local, and tribal
governments, in the aggregate, or the private sector in any one year.
As discussed in the TSD and preamble for the interim final rule, we
determined the maximum annual cost of compliance with this rule on the
oil and natural gas industry is estimated to be approximately $50
million. However, we believe this is a conservative estimate and that
actual annual costs would be much lower due to factors such as
increased facility well density, standard industry practice to use VOC
control equipment, and anticipated pipeline infrastructure development,
which is explained further in the TSD. Thus, this rule is not subject
to the requirements of sections 202 or 205 of UMRA.
    This rule does not contain a significant federal intergovernmental

mandate as described by section 203 of UMRA. Therefore, this rule is
also not subject to the requirements of section 203 of UMRA because it
contains no regulatory requirements that might significantly or
uniquely affect small governments.

E. Executive Order 13132: Federalism

    This action does not have federalism implications. It will not have
substantial direct effects on the States, on the relationship between
the national government and the States, or on the distribution of power
and responsibilities among the various levels of government, as
specified in Executive Order 13132. This rule regulates under the CAA
certain stationary sources in Indian country that are not subject to
approved CAA programs of the State of North Dakota. Thus, Executive
Order 13132 does not apply to this action. Although section 6 of
Executive Order 13132 does not apply to this action, we consulted with
the Three Affiliated Tribes of the Mandan, Hidatsa, and Arikara Nation
in developing this action. A summary of the consultation is provided
below in section F of this preamble. In the spirit of Executive Order
13132, and consistent with EPA policy to promote communications between
EPA and State and local governments, EPA specifically solicited comment
on the proposed action from State and local officials.

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

    Executive Order 13175, entitled ``Consultation and Coordination
with Indian Tribal Governments'' (65 FR 67249, November 6, 2000),
requires us to develop an accountable process to ensure ``meaningful
and timely input by tribal officials in the development of regulatory
policies that have tribal implications.'' ``Policies that have tribal
implications'' is defined in the Executive Order to include regulations
that have ``substantial direct effects on one or more Indian tribes, on
the relationship between the Federal Government and the Indian tribes,
or on the distribution of power and responsibilities between the
Federal Government and Indian tribes.''
    Under Section 5(b) of Executive Order 13175, we may not issue a
regulation that has tribal implications, that imposes substantial
direct compliance costs, and that is not required by statute, unless
the Federal Government provides the funds necessary to pay the direct
compliance costs incurred by tribal governments, or we consult with
tribal officials early in the process of developing the proposed
regulation. Under Section 5(c) of Executive Order 13175, we may not
issue a regulation that has tribal implications and that preempts
tribal law, unless the Agency consults with tribal officials early in
the process of developing the proposed regulation.
    We concluded that this final rule will have tribal implications.
However, it will neither impose substantial direct compliance costs on
tribal governments, nor preempt tribal law. These regulations would
affect the FBIR community by establishing air quality regulations and
thus creating a level of air quality protection not previously provided
under the CAA. The regulatory approach used in this rule would create
federal requirements similar to those that are already in place areas
adjacent to the Reservation. Finally, although tribal governments are
encouraged to partner with us on the implementation of these
regulations, they are not required to do so. Since this final rule will
neither impose substantial direct compliance costs on tribal
governments, nor preempt tribal law, the requirements of Sections 5(b)
and 5(c) of the Executive Order do not apply to this rule.
    Consistent with EPA policy, the EPA consulted with tribal officials
and representatives of the Three Affiliated Tribes of the Mandan,
Hidatsa and Arikara Nation early in the process of developing this
regulation to permit them to have meaningful and timely input into its
development.
    Tribal consultation with the Three Affiliated Tribes of the Mandan,
Hidatsa, and Arikara Nation was first initiated on February 17, 2012
when we mailed a letter inviting the Tribes to consult on the first
group of synthetic minor NSR permits being issued on the Reservation
under the Federal Tribal NSR Rule. Then, on March 29, 2012, EPA senior
management and the Chairman of the Three Affiliated Tribes of the
Mandan, Hidatsa, and Arikara Nation along with other government
officials met via conference call to discuss the proposed FIP to be
developed for the FBIR. We formally invited the Tribes to consult about
this FIP in a letter dated April 10, 2012 to Chairman Tex Hall, of the
Three Affiliated Tribes of the Mandan, Hidatsa, and Arikara Nation
Council.
    We again met with members of the Three Affiliated Tribes of the
Mandan, Hidatsa, and Arikara Nation Council on June 13, 2012 in New
Town to consult and receive input from the Tribes as we developed this
FIP. In attendance from the Council were the vice Chairman and two
council members. The Tribes' legal counsel was also in attendance. The
purpose of the consultation was twofold: (1) Update the Tribes on the
EPA's efforts to develop this FIP so that the air quality on the FBIR
is protected and oil and natural gas development continues; and (2)
discuss the Tribes' preferences regarding involvement in the FIP
process. We provided information on our plan to prepare a FIP to ensure
air quality protection while preventing delays in oil and natural gas
production. We solicited the Tribes' input on the FIP development. The
Council members present at the consultation meeting indicated that they
strongly desired this FIP to be consistent with North Dakota's
requirements for oil and natural gas production facilities in order to
keep a level playing field for development and continue uninterrupted
development of a key economic resource for the Tribes. The Council
members expressed interest in the future delegation of this FIP so that
the Tribes can implement the rule in place of us. The Council members
also expressed interest in providing the Tribes' assistance in setting
up a public hearing for the rule.
    As noted above, the Three Affiliated Tribes of the Mandan, Hidatsa
and Arikara Nation have indicated preliminary interest in seeking
administrative delegation of the Federal Tribal NSR rule to assist us
with administration of that rule. We will continue to work with the
Three Affiliated Tribes of the Mandan, Hidatsa, and Arikara Nation if
administrative delegation is something the Tribes decide to pursue.
    Information containing the consultation process is contained in the
docket for this rule.
    For purposes of the final rule, we specifically solicited
additional comments on the proposed action from tribal officials. We
did not receive any comments on the proposed rule from tribal officials
during the public comment period.

G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks

    The EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as
applying only to those regulatory actions that concern health or safety
risks, such that the analysis required under section 5-501 of the EO
has the potential to influence the regulation. This action is not
subject to EO 13045 because the Agency does not believe the
environmental or safety risks addressed by this action present a
disproportionate risk to children. In addition, this rule requires
control and reduction of emissions of VOCs, which

will have a beneficial effect on children's health by reducing air
pollution.

H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use

    This action is not subject to Executive Order 13211 (66 FR 28355,
May 22, 2001), because it is not a significant regulatory action under
Executive Order 12866.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (``NTTAA''), Public Law 104-113, 12(d) (15 U.S.C. 272 note)
directs us to use voluntary consensus standards in its regulatory
activities unless to do so would be inconsistent with applicable law or
otherwise impractical. Voluntary consensus standards are technical
standards (e.g., materials specifications, test methods, sampling
procedures, and business practices) that are developed or adopted by
voluntary consensus standards bodies. NTTAA directs us to provide
Congress, through OMB, explanations when the Agency decides not to use
available and applicable voluntary consensus standards.
    This rulemaking does not involve technical standards. Therefore, we
did not consider the use of any voluntary consensus standards.

J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations

    Executive Order 12898 (59 FR 7629, February 16, 1994), establishes
federal executive policy on environmental justice. Its main provision
directs federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority populations and low-income
populations in the United States.
    We did a demographic analysis of the areas closest to sources
likely to be covered by this rule, and found disproportionately high
concentrations of minority and low income populations. As detailed in
our response to comments, we took substantial steps to ensure that such
populations were given the opportunity for meaningful participation in
the development of the rule. In addition, we conducted an EJ analysis
that determined that this rule will not have disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority, low-income, and indigenous
populations, because it ensures compliance with the NAAQS, which
provides environmental and public health protection for all affected
populations, including minority, low-income, and indigenous
populations.\34\
---------------------------------------------------------------------------

    \34\ The TSD includes a more detailed explanation of the EJ
analysis for this FIP. It can be found in the docket for this rule,
Docket ID: EPA-R08-OAR-2012-0479, which can be accessed at: http://www.regulations.gov.
---------------------------------------------------------------------------

K. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the
Small Business Regulatory Enforcement Fairness Act of 1996, generally
provides that before a rule may take effect, the agency promulgating
the rule must submit a rule report, which includes a copy of the rule,
to each House of the Congress and to the Comptroller General of the
United States. The EPA will submit a report containing this rule and
other required information to the U.S. Senate, the U.S. House of
Representatives and the Comptroller General of the United States prior
to publication of the rule in the Federal Register. A major rule cannot
take effect until 60 days after it is published in the Federal
Register. This action is not a ``major rule'' as defined by 5 U.S.C.
804(2). This rule will be effective 30 days from the date of
publication, i.e., on April 22, 2013.

L. Judicial Review

    Under section 307(b)(1) of the Act, petitions for judicial review
of this action must be filed in the United States Court of Appeals for
the appropriate circuit by May 21, 2013. Any such judicial review is
limited to only those objections that are raised with reasonable
specificity in timely comments. Filing a petition for reconsideration
by the Administrator of this final rule does not affect the finality of
this rule for the purposes of judicial review nor does it extend the
time within which a petition for judicial review may be filed and shall
not postpone the effectiveness of such rule or action. Under section
307(b)(2) of the Act, the requirements of this final action may not be
challenged later in civil or criminal proceedings brought by us to
enforce these requirements.

List of Subjects in 40 CFR Part 49

    Environmental protection, Administrative practice and procedure,
Air pollution control, Indians, Intergovernmental relations, Reporting
and recordkeeping requirements.

    Dated: March 1, 2013.
Bob Perciasepe,
Acting Administrator.

    40 CFR part 49 is amended as follows:

PART 49--[AMENDED]

0
1. The authority citation for part 49 continues to read as follows:

    Authority:  42 U.S.C. 7401, et seq.

PART 49--INDIAN COUNTRY: AIR QUALITY PLANNING AND MANAGEMENT

Subpart K--Implementation Plans for Tribes--Region VIII

0
2. Add Sec. Sec.  49.4161 through 49.4168 and an undesignated center
heading to appear immediately before the newly added Sec.  49.4161 to
read as follows:
* * * * *

Federal Implementation Plan for Oil and Natural Gas Well Production
Facilities; Fort Berthold Indian Reservation (Mandan, Hidatsa and
Arikara Nation), North Dakota

Sec.
Subpart
49.4161 Introduction.
49.4162 Delegation of authority of administration to the tribes.
49.4163 General provisions.
49.4164 Construction and operational control measures.
49.4165 Control equipment requirements.
49.4166 Monitoring requirements.
49.4167 Recordkeeping requirements.
49.4168 Notification and reporting requirements.
* * * * *

Federal Implementation Plan for Oil and Natural Gas Well Production
Facilities; Fort Berthold Indian Reservation (Mandan, Hidatsa and
Arikara Nation), North Dakota

Sec.  49.4161  Introduction.

    (a) What is the purpose of Sec. Sec.  49.4161 through 49.4168?
Sections 49.4161 through 49.4168 establish legally and practicably
enforceable requirements to control and reduce VOC emissions from well
completion operations, well recompletion operations, production
operations, and storage operations at existing, new and modified oil
and natural gas production facilities.
    (b) Am I subject to Sec. Sec.  49.4161 through 49.4168? Sections
49.4161 through 49.4168 apply to each owner or operator constructing,
modifying or operating an oil and natural gas production facility

producing from the Bakken Pool with one or more oil and natural gas
wells, for any one of which completion or recompletion operations are/
were performed on or after August 12, 2007, that is located on the Fort
Berthold Indian Reservation, which is defined by the Act of March 3,
1891 (26 Statute 1032) and which includes all lands added to the
Reservation by Executive Order of June 17, 1892 (the ``Fort Berthold
Indian Reservation''). For the purposes of this subpart, the date that
the first well completion operation at a new oil and natural gas
production facility was initiated is the date that initial construction
has commenced. For the purposes of this subpart, the date that a new
well completion operation or the date that an existing well
recompletion operation at an existing oil and natural gas production
facility is initiated is the date that a modification has commenced.
    (c) When must I comply with Sec. Sec.  49.4161 through 49.4168?
Compliance with Sec. Sec.  49.4161 through 49.4168 is required no later
than June 20, 2013 or upon initiation of well completion operations or
well recompletion operations, whichever is later.

Sec.  49.4162  Delegation of authority of administration to the tribes.

    (a) What is the purpose of this section? The purpose of this
section is to establish the process by which the Regional Administrator
may delegate to the Mandan, Hidatsa and Arikara Nation the authority to
assist the EPA with administration of this Federal Implementation Plan
(FIP). This section provides for administrative delegation and does not
affect the eligibility criteria under 40 CFR 49.6 for treatment in the
same manner as a state.
    (b) How does the Tribe request delegation? In order to be delegated
authority to assist us with administration of this FIP, the authorized
representative of the Mandan, Hidatsa and Arikara Nation must submit a
request to the Regional Administrator that:
    (1) Identifies the specific provisions for which delegation is
requested;
    (2) Includes a statement by the Mandan, Hidatsa and Arikara
Nation's legal counsel (or equivalent official) that includes the
following information:
    (i) A statement that the Mandan, Hidatsa and Arikara Nation are an
Indian Tribe recognized by the Secretary of the Interior;
    (ii) A descriptive statement demonstrating that the Mandan, Hidatsa
and Arikara Nation are currently carrying out substantial governmental
duties and powers over a defined area and that meets the requirements
of Sec.  49.7(a)(2); and
    (iii) A description of the laws of the Mandan, Hidatsa and Arikara
Nation that provide adequate authority to carry out the aspects of the
rule for which delegation is requested.
    (3) Demonstrates that the Mandan, Hidatsa and Arikara Nation have,
or will have, adequate resources to carry out the aspects of the rule
for which delegation is requested.
    (c) How is the delegation of administration accomplished? (1) A
Delegation of Authority Agreement will set forth the terms and
conditions of the delegation, will specify the rule and provisions that
the Mandan, Hidatsa and Arikara Nation shall be authorized to implement
on behalf of the EPA, and shall be entered into by the Regional
Administrator and the Mandan, Hidatsa and Arikara Nation. The Agreement
will become effective upon the date that both the Regional
Administrator and the authorized representative of the Mandan, Hidatsa
and Arikara Nation have signed the Agreement. Once the delegation
becomes effective, the Mandan, Hidatsa and Arikara Nation will be
responsible, to the extent specified in the Agreement, for assisting us
with administration of this FIP and shall act as the Regional
Administrator as that term is used in these regulations. Any Delegation
of Authority Agreement will clarify the circumstances in which the term
``Regional Administrator''' found throughout this FIP is to remain the
EPA Regional Administrator and when it is intended to refer to the
``Mandan, Hidatsa and Arikara Nation,'' instead.
    (2) A Delegation of Authority Agreement may be modified, amended,
or revoked, in part or in whole, by the Regional Administrator after
consultation with the Mandan, Hidatsa and Arikara Nation.
    (d) How will any delegation of authority agreement be publicized?
The Regional Administrator shall publish a notice in the Federal
Register informing the public of any delegation of authority agreement
with the Mandan, Hidatsa and Arikara Nation to assist us with
administration of all or a portion of this FIP and will identify such
delegation in the FIP. The Regional Administrator shall also publish an
announcement of the delegation of authority agreement in local
newspapers.

Sec.  49.4163  General provisions.

    (a) Definitions. As used in Sec. Sec.  49.4161 through 49.4168, all
terms not defined herein shall have the meaning given them in the Act,
in subpart A and subpart OOOO of 40 CFR part 60, in the Prevention of
Significant Deterioration regulations at 40 CFR 52.21, or in the
Federal Minor New Source Review Program in Indian Country at 40 CFR
49.151. The following terms shall have the specific meanings given
them.
    (1) Bakken Pool means Oil produced from the Bakken, Three Forks,
and Sanish Formations.
    (2) Breathing losses means natural gas emissions from fixed roof
tanks resulting from evaporative losses during storage.
    (3) Casinghead natural gas means the associated natural gas that
naturally dissolves out of reservoir fluids during well completion
operations and recompletion operations due to the pressure relief that
occurs as the reservoir fluids travel up the well casinghead.
    (4) Closed vent system means a system that is not open to the
atmosphere and that is composed of hard-piping, ductwork, connections,
and, if necessary, flow-inducing devices that transport natural gas
from a piece or pieces of equipment to a control device or back to a
process.
    (5) Enclosed combustor means a thermal oxidation system with an
enclosed combustion chamber that maintains a limited constant
temperature by controlling fuel and combustion air.
    (6) Existing facility means an oil and natural gas production
facility that begins actual construction prior to the effective date of
the ``Federal Implementation Plan for Oil and Natural Gas Well
Production Facilities; Fort Berthold Indian Reservation (Mandan,
Hidatsa and Arikara Nation), North Dakota''.
    (7) Flashing losses means natural gas emissions resulting from the
presence of dissolved natural gas in the produced oil and the produced
water, both of which are under high pressure, that occurs as the
produced oil and produced water is transferred to storage tanks or
other vessels that are at atmospheric pressure.
    (8) Modified facility means a facility which has undergone the
addition, completion, or recompletion of one or more oil and natural
gas wells, and/or the addition of any associated equipment necessary
for production and storage operations at an existing facility.
    (9) New facility means an oil and natural gas production facility
that begins actual construction after the effective date of the
``Federal Implementation Plan for Oil and Natural Gas Well Production
Facilities; Fort Berthold Indian Reservation (Mandan,

Hidatsa and Arikara Nation), North Dakota''.
    (10) Oil means hydrocarbon liquids.
    (11) Oil and natural gas production facility means all of the air
pollution emitting units and activities located on or integrally
connected to one or more oil and natural gas wells that are necessary
for production operations and storage operations.
    (12) Oil and natural gas well means a single well that extracts
subsurface reservoir fluids containing a mixture of oil, natural gas,
and water.
    (13) Owner or operator means any person who owns, leases, operates,
controls, or supervises an oil and natural gas production facility.
    (14) Permit to construct or construction permit means a permit
issued by the Regional Administrator pursuant to 40 CFR 49.151, 52.10
or 52.21, or a permit issued by a tribe pursuant to a program approved
by the Administrator under 40 CFR part 51, subpart I, authorizing the
construction or modification of a stationary source.
    (15) Permit to operate or operating permit means a permit issued by
the Regional Administrator pursuant to 40 CFR part 71, or by a tribe
pursuant to a program approved by the Administrator under 40 CFR part
51 or 40 CFR part 70, authorizing the operation of a stationary source.
    (16) Pit flare means an ignition device, installed horizontally or
vertically and used in oil and natural gas production operations to
combust produced natural gas and natural gas emissions.
    (17) Produced natural gas means natural gas that is separated from
extracted reservoir fluids during production operations.
    (18) Produced oil means oil that is separated from extracted
reservoir fluids during production operations.
    (19) Produced oil storage tank means a unit that is constructed
primarily of non-earthen materials (such as steel, fiberglass, or
plastic) which provides structural support and is designed to contain
an accumulation of produced oil.
    (20) Produced water means water that is separated from extracted
reservoir fluids during production operations.
    (21) Produced water storage tank means a unit that is constructed
primarily of non-earthen materials (such as steel, fiberglass, or
plastic) which provides structural support and is designed to contain
an accumulation of produced water.
    (22) Production operations means the extraction and separation of
reservoir fluids from an oil and natural gas well, using separators and
heater-treater systems. A separator is a pressurized vessel designed to
separate reservoir fluids into their constituent components of oil,
natural gas and water. A heater-treater is a unit that heats the
reservoir fluid to break oil/water emulsions and to reduce the oil
viscosity. The water is then typically removed by using gravity to
allow the water to separate from the oil.
    (23) Regional Administrator means the Regional Administrator of EPA
Region 8 or an authorized representative of the Regional Administrator.
    (24) Standing losses means natural gas emissions from fixed roof
tanks as a result of evaporative losses during storage.
    (25) Storage operations means the transfer of produced oil and
produced water to storage tanks, the filling of the storage tanks, the
storage of the produced oil and produced water in the storage tanks,
and the draining of the produced oil and produced water from the
storage tanks.
    (26) Supervisory Control and Data Acquisition (SCADA) system
generally refers to industrial control computer systems that monitor
and control industrial infrastructure or facility-based processes.
    (27) Utility flare means thermal oxidation system using an open
(without enclosure) flame. An enclosed combustor as defined in
Sec. Sec.  49.4161 through 49.4168 is not considered a flare.
    (28) Visible Smoke emissions means a pollutant generated by thermal
oxidation in a flare or enclosed combustor and occurring immediately
downstream of the flame. Visible smoke occurring within, but not
downstream of, the flame, is not considered to constitute visible smoke
emissions.
    (29) Well completion means the process that allows for the flowback
of oil and natural gas from newly drilled wells to expel drilling and
reservoir fluids and tests the reservoir flow characteristics, which
may vent produced hydrocarbons to the atmosphere via an open pit or
tank.
    (30) Well completion operation means any oil and natural gas well
completion using hydraulic fracturing occurring at an oil and natural
gas production facility.
    (31) Well recompletion operation means any oil and natural gas well
completion using hydraulic refracturing occurring at an oil and natural
gas production facility.
    (32) Working losses means natural gas emissions from fixed roof
tanks resulting from evaporative losses during filling and emptying
operations.
    (b) Requirement for testing. The Regional Administrator may require
that an owner or operator of an oil and natural gas production facility
demonstrate compliance with the requirements of the ``Federal
Implementation Plan for Oil and Natural Gas Well Production Facilities;
Fort Berthold Indian Reservation (Mandan, Hidatsa and Arikara Nation),
North Dakota'' by performing a source test and submitting the test
results to the Regional Administrator. Nothing in the ``Federal
Implementation Plan for Oil and Natural Gas Well Production Facilities;
Fort Berthold Indian Reservation (Mandan, Hidatsa and Arikara Nation),
North Dakota'' limits the authority of the Regional Administrator to
require, in an information request pursuant to section 114 of the Act,
an owner or operator of an oil and natural gas production facility
subject to the ``Federal Implementation Plan for Oil and Natural Gas
Production Facilities, Fort Berthold Indian Reservation (Mandan,
Hidatsa and Arikara Nation)'' to demonstrate compliance by performing
testing, even where the facility does not have a permit to construct or
a permit to operate.
    (c) Requirement for monitoring, recordkeeping, and reporting.
Nothing in ``Federal Implementation Plan for Oil and Natural Gas
Production Facilities, Fort Berthold Indian Reservation (Mandan,
Hidatsa and Arikara Nation)'' precludes the Regional Administrator from
requiring monitoring, recordkeeping and reporting, including
monitoring, recordkeeping and reporting in addition to that already
required by an applicable requirement in these rules, in a permit to
construct or permit to operate in order to ensure compliance.
    (d) Credible evidence. For the purposes of submitting reports or
establishing whether or not an owner or operator of an oil and natural
gas production facility has violated or is in violation of any
requirement, nothing in the ``Federal Implementation Plan for Oil and
Natural Gas Well Production Facilities; Fort Berthold Indian
Reservation (Mandan, Hidatsa and Arikara Nation), North Dakota'' shall
preclude the use, including the exclusive use, of any credible evidence
or information, relevant to whether a facility would have been in
compliance with applicable requirements if the appropriate performance
or compliance test had been performed.

Sec.  49.4164  Construction and operational control measures.

    (a) Each owner or operator must operate and maintain all liquid and
gas collection, storage, processing and handling operations, regardless
of size, so as to minimize leakage of natural gas emissions to the
atmosphere.
    (b) During all oil and natural gas well completion operations or
recompletion operations at an oil and natural gas production facility
and prior to the first date of production of each oil and natural gas
well, each owner or operator must, at a minimum, route all casinghead
natural gas to a utility flare or a pit flare capable of reducing the
mass content of VOC in the natural gas emissions vented to it by at
least 90.0 percent or greater and operated as specified in Sec. Sec.
49.4165 and 49.4166.
    (c) Beginning with the first date of production from any one oil
and natural gas well at an oil and natural gas production facility,
each owner or operator must, at a minimum, route all natural gas
emissions from production operations and storage operations to a
control device capable of reducing the mass content of VOC in the
natural gas emissions vented to it by at least 90.0 percent or greater
and operated as specified in Sec. Sec.  49.4165 and 49.4166.
    (d) Within ninety (90) days of the first date of production from
any oil and natural gas well at an oil and natural gas production
facility, each owner or operator must:
    (1) Route the produced natural gas from the production operations
through a closed-vent system to:
    (i) An operating system designed to recover and inject all the
produced natural gas into a natural gas gathering pipeline system for
sale or other beneficial purpose; or
    (ii) A utility flare or equivalent combustion device capable of
reducing the mass content of VOC in the produced natural gas vented to
the device by at least 98.0 percent or greater and operated as
specified in Sec. Sec.  49.4165 and 49.4166.
    (2) Route all standing, working, breathing, and flashing losses
from the produced oil storage tanks and any produced water storage tank
interconnected with the produced oil storage tanks through a closed-
vent system to:
    (i) An operating system designed to recover and inject the natural
gas emissions into a natural gas gathering pipeline system for sale or
other beneficial purpose; or
    (ii) An enclosed combustor or utility flare capable of reducing the
mass content of VOC in the natural gas emissions vented to the device
by at least 98.0 percent or greater and operated as specified in
Sec. Sec.  49.4165(c) and 49.4166.
    (iii) If the uncontrolled potential to emit VOCs from the aggregate
of all produced oil storage tanks and produced water storage tanks
interconnected with produced oil storage tanks at an oil and natural
gas production facility is less than, and reasonably expected to remain
below, 20 tons in any consecutive 12-month period, then, upon prior
written approval by the EPA the owner or operator may use a pit flare,
an enclosed combustor or a utility flare that is capable of reducing
the mass content of VOC in the natural gas emissions from the storage
tanks vented to the device by only 90.0 percent.
    (e) In the event that pipeline injection of all or part of the
natural gas collected in an operating system designed to recover and
inject natural gas becomes temporarily infeasible and there is no
operational enclosed combustor or utility flare at the facility, the
owner or operator must route the natural gas that cannot be injected
through a closed-vent system to a pit flare operated as specified in
Sec. Sec.  49.4165 and 49.4166.
    (f) Produced oil storage tanks and any produced water storage tanks
interconnected with produced oil storage tanks subject to the
requirements specified in 40 CFR part 60, subpart OOOO are considered
to meet the requirements of Sec.  49.4164(d)(2). No further
requirements apply for such storage tanks under Sec.  49.4164(d)(2).

Sec.  49.4165  Control equipment requirements.

    (a) Covers. Each owner or operator must equip all openings on each
produced oil storage tank and produced water storage tank
interconnected with produced oil storage tanks with a cover to ensure
that all natural gas emissions are efficiently being routed through a
closed-vent system to a vapor recovery system, an enclosed combustor, a
utility flare, or a pit flare.
    (1) Each cover and all openings on the cover (e.g., access hatches,
sampling ports, pressure relief valves (PRV), and gauge wells) shall
form a continuous impermeable barrier over the entire surface area of
the produced oil and produced water in the storage tank.
    (2) Each cover opening shall be secured in a closed, sealed
position (e.g., covered by a gasketed lid or cap) whenever material is
in the unit on which the cover is installed except during those times
when it is necessary to use an opening as follows:
    (i) To add material to, or remove material from the unit (this
includes openings necessary to equalize or balance the internal
pressure of the unit following changes in the level of the material in
the unit);
    (ii) To inspect or sample the material in the unit; or
    (iii) To inspect, maintain, repair, or replace equipment located
inside the unit.
    (3) Each thief hatch cover shall be weighted and properly seated.
    (4) Each PRV shall be set to release at a pressure that will ensure
that natural gas emissions are routed through the closed-vent system to
the vapor recovery system, the enclosed combustor, or the utility flare
under normal operating conditions.
    (b) Closed-vent systems. Each owner or operator must meet the
following requirements for closed-vent systems:
    (1) Each closed-vent system must route all produced natural gas and
natural gas emissions from production and storage operations to the
natural gas sales pipeline or the control devices required by paragraph
(a) of this section.
    (2) All vent lines, connections, fittings, valves, relief valves,
or any other appurtenance employed to contain and collect natural gas,
vapor, and fumes and transport them to a natural gas sales pipeline and
any VOC control equipment must be maintained and operated properly at
all times.
    (3) Each closed-vent system must be designed to operate with no
detectable natural gas emissions.
    (4) If any closed-vent system contains one or more bypass devices,
except as provided for in paragraph (b)(4)(iii) of this section, that
could be used to divert all or a portion of the natural gas emissions,
from entering a natural gas sales pipeline and/or any control devices,
the owner or operator must meet the one of following requirements for
each bypass device:
    (i) At the inlet to the bypass device that could divert the natural
gas emissions away from a natural gas sales pipeline or a control
device and into the atmosphere, properly install, calibrate, maintain,
and operate a natural gas flow indicator that is capable of taking
continuous readings and sounding an alarm when the bypass device is
open such that natural gas emissions are being, or could be, diverted
away from a natural gas sales pipeline or a control device and into the
atmosphere;
    (ii) Secure the bypass device valve installed at the inlet to the
bypass device in the non-diverting position using a car-seal or a lock-
and-key type configuration;
    (iii) Low leg drains, high point bleeds, analyzer vents, open-ended
valves or lines, and safety devices are not subject

to the requirements applicable to bypass devices.
    (c) Enclosed combustors and utility flares. Each owner or operator
must meet the following requirements for enclosed combustors and
utility flares:
    (1) For each enclosed combustor or utility flare, the owner or
operator must follow the manufacturer's written operating instructions,
procedures and maintenance schedule to ensure good air pollution
control practices for minimizing emissions;
    (2) For each enclosed combustor or utility flare, the owner or
operator must ensure there is sufficient capacity to reduce the mass
content of VOC in the produced natural gas and natural gas emissions
routed to it by at least 98.0 percent for the minimum and maximum
natural gas volumetric flow rate and BTU content routed to the device;
    (3) Each enclosed combustor or utility flare must be operated to
reduce the mass content of VOC in the produced natural gas and natural
gas emissions routed to it by at least 98.0 percent;
    (4) The owner or operator must ensure that each utility flare is
designed and operated in accordance with the requirements of 40 CFR
60.18(b) for such flares, except for Sec.  60.18(c)(2) and (f)(2) for
those utility flares operated with an electronically controlled
automatic igniter.
    (5) The owner or operator must ensure that each enclosed combustor
is:
    (i) A model demonstrated by a manufacturer to the meet the VOC
destruction efficiency requirements of Sec. Sec.  49.4161 through
49.4168 using the procedure specified in 40 CFR part 60, subpart OOOO
at Sec.  60.5413(d) by the due date of the first annual report as
specified in Sec.  49.4168(b); or
    (ii) Demonstrated to meet the VOC destruction efficiency
requirements of Sec. Sec.  49.4161 through 49.4168 using EPA approved
performance test methods specified in 40 CFR part 60, subpart OOOO at
Sec.  60.5413(b) by the due date of the first annual report as
specified in Sec.  49.4168(b).
    (6) The owner or operator must ensure that each enclosed combustor
and utility flare is:
    (i) Operated properly at all times that produced natural gas and/or
natural gas emissions are routed to it;
    (ii) Operated with a liquid knock-out system to collect any
condensable vapors (to prevent liquids from going through the control
device);
    (iii) Equipped with a flash-back flame arrestor;
    (iv) Equipped with one of the following:
    (A) A continuous burning pilot flame.
    (B) An electronically controlled automatic igniter;
    (v) Equipped with a monitoring system for continuous recording of
the parameters that indicate proper operation of each enclosed
combustor, utility flare, continuous burning pilot flame, and
electronically controlled automatic igniter, such as a chart recorder,
data logger or similar devices;
    (vi) Maintained in a leak-free condition; and
    (vii) Operated with no visible smoke emissions.
    (d) Pit Flares. Each owner or operator must meet the following
requirements for pit flares:
    (1) The owner or operator must develop written operating
instructions, operating procedures and maintenance schedules to ensure
good air pollution control practices for minimizing emissions from the
pit flare based on the site-specific design.
    (2) The owner or operator must only use a pit flare for the
following operations:
    (i) To control produced natural gas and natural gas emissions
during well completion operations or recompletion operations;
    (ii) To control produced natural gas and natural gas emissions in
the event that natural gas recovered for pipeline injection must be
diverted to a backup control device because injection is temporarily
infeasible and there is no operational enclosed combustor or utility
flare at the oil and natural gas production facility. Use of the pit
flare for this situation is limited to a maximum of 500 hours in any
twelve (12) consecutive months; or
    (iii) Control of standing, working, breathing, and flashing losses
from the produced oil storage tanks and any produced water storage tank
interconnected with the produced oil storage tanks if the uncontrolled
potential VOC emissions from the aggregate of all produced oil storage
tanks and produced water storage tanks interconnected with produced oil
storage tanks is less than, and reasonably expected to remain below, 20
tons in any consecutive 12-month period.
    (3) The owner or operator must only use the pit flare under the
following conditions and limitations:
    (i) The pit flare is operated to reduce the mass content of VOC in
the produced natural gas and natural gas emissions routed to it by at
least 90.0 percent;
    (ii) The pit flare is operated in accordance with the site-specific
written operating instructions, operating procedures, and maintenance
schedules to ensure good air pollution control practices for minimizing
emissions;
    (iii) The pit flare is operated with no visible smoke emissions;
    (iv) The pit flare is equipped with an electronically controlled
automatic igniter;
    (v) The pit flare is visually inspected for the presence of a flame
anytime produced natural gas or natural gas emissions are being routed
to it. Should the flame fail, the flame must be relit as soon as safely
possible and the electronically controlled automatic igniter must be
repaired or replaced before the pit flare is utilized again; and
    (vi) The owner or operator does not deposit or cause to be
deposited into a flare pit any oil field fluids or oil and natural gas
wastes other than those designed to go to the pit flare.
    (e) Other Control Devices. Upon prior written approval by the EPA,
the owner or operator may use control devices other than those listed
above that are determined by EPA to be capable of reducing the mass
content of VOC in the natural gas routed to it by at least 98.0
percent, provided that:
    (1) In operating such control devices, the owner or operator must
follow the manufacturer's written operating instructions, procedures
and maintenance schedule to ensure good air pollution control practices
for minimizing emissions; and
    (2) The owner or operator must ensure there is sufficient capacity
to reduce the mass content of VOC in the produced natural gas and
natural gas emissions routed to such other control devices by at least
98.0 percent for the minimum and maximum natural gas volumetric flow
rate and BTU content routed to each device.
    (3) The owner or operator must operate such a control device to
reduce the mass content of VOC in the produced natural gas and natural
gas emissions routed to it by at least 98.0 percent.

Sec.  49.4166  Monitoring requirements.

    (a) Each owner and operator must measure the barrels of oil
produced at the oil and natural gas production facility each time the
oil is unloaded from the produced oil storage tanks using the
methodologies of tank gauging or positive displacement metering system,
as appropriate, as established by the U.S. Department of the Interior's
Bureau of Land Management at 43 CFR part 3160, in the ``Onshore Oil and
Gas Operations; Federal and Indian Oil & Gas Leases; Onshore Oil and
Gas Order No. 4; Measurement of Oil''.
    (b) Each owner or operator must monitor the hours that each pit
flare is

operated to control produced natural gas and natural gas emissions in
the event that natural gas recovered for pipeline injection must be
diverted to a backup control device because injection is temporarily
infeasible and there is no enclosed combustor or utility flare at the
oil and natural gas production facility.
    (c) Each owner or operator must monitor the volume of produced
natural gas sent to each enclosed combustor, utility flare, and pit
flare at all times. Methods to measure the volume include, but are not
limited to, direct measurement and gas-to-oil ratio (GOR) laboratory
analyses.
    (d) Each owner or operator must monitor the volume of standing,
working, breathing, and flashing losses from the produced oil and
produced water storage tanks sent to each vapor recovery system,
enclosed combustor, utility flare, and pit flare at all times. Methods
to measure the volume include, but are not limited to, direct
measurement or GOR laboratory analyses.
    (e) Each owner or operator must perform quarterly visual
inspections of tank thief hatches, covers, seals, PRVs, and closed vent
systems to ensure proper condition and functioning and repair any
damaged equipment. The quarterly inspections must be performed while
the produced oil and produced water storage tanks are being filled.
    (f) Each owner or operator must perform quarterly visual
inspections of the peak pressure and vacuum values in each closed vent
system and control system for the produced oil and produced water
storage tanks to ensure that the pressure and vacuum relief set-points
are not being exceeded in a way that has resulted, or may result, in
venting and possible damage to equipment. The quarterly inspections
must be performed while the produced oil and produced water storage
tanks are being filled.
    (g) Each owner or operator must monitor the operation of each
enclosed combustor, utility flare, and pit flare to confirm proper
operation as follows:
    (1) Continuously monitor all variable operational parameters
specified in the written operating instructions and procedures,
including continuous burning pilot flame, electronically controlled
automatic igniters, and monitoring system failures, using a malfunction
alarm and remote notification system, where such systems are available,
or continuously monitor under an equivalent alternative protocol upon
prior written approval by the EPA;
    (2) Perform a physical inspection of all equipment associated with
each enclosed combustor, utility flare, and pit flare each time an
operator is on site, at a minimum quarterly, to ensure system
integrity;
    (3) Monitor for visible smoke during operation of any enclosed
combustor, utility flare or pit flare each time an operator is on site,
at a minimum quarterly. Upon observation of visible smoke, use EPA
Reference Method 22 of 40 CFR part 60, Appendix A, to determine whether
visible smoke emissions are present. The observation period shall be 2
hours. Visible smoke emissions are present if smoke is observed for
more than 5 minutes in any 2 consecutive hours; and
    (4) Respond to any observation of any continuous burning pilot
flame failure, electronically controlled automatic igniter failure, or
improper monitoring equipment operation and ensure the equipment is
returned to proper operation as soon as practicable and safely possible
after an observation or an alarm sounds.
    (h) Where sufficient to meet the monitoring and recordkeeping
requirements in Sec. Sec.  49.4166 and 49.4167, the owner or operator
may use a Supervisory Control and Data Acquisition (SCADA) system to
monitor and record the required data in Sec. Sec.  49.4161 through
49.4168.
    (i) Other Monitoring Options. The owner or operator may use
equivalent methods of monitoring other than those listed above upon
prior written approval by the EPA.

Sec.  49.4167  Recordkeeping requirements.

    (a) Each owner or operator must maintain the following records:
    (1) The measured barrels of oil produced at the oil and natural gas
production facility each time the oil is unloaded from the produced oil
storage tanks;
    (2) The volume of produced natural gas sent to each enclosed
combustor, utility flare, and pit flare at all times;
    (3) The volume of natural gas emissions from the produced oil
storage tanks and produced water storage tanks sent to each enclosed
combustor, utility flare, and pit flare at all times;
    (4) A summary of each oil and natural gas well completion operation
and recompletion operation at an oil and natural gas production
facility. Each summary shall include:
    (i) The latitude and longitude location of the oil and natural gas
well in decimal format;
    (ii) The date, time, and duration in hours of flowback from the oil
and natural gas well;
    (iii) The date, time, and duration in hours of any venting of
casinghead natural gas from the oil and natural gas well; and
    (iv) Specific reasons for each instance of venting in lieu of
capture or combustion.
    (5) For each enclosed combustor, utility flare, and pit flare at an
oil and natural gas production facility:
    (i) Written, site-specific designs, operating instructions,
operating procedures and maintenance schedules;
    (ii) Records of all required monitoring of operations;
    (iii) Records of any deviations from the operating parameters
specified by the written site-specific designs, operating instructions,
and operating procedures. The records must include the enclosed
combustor, utility flare, or pit flare's total operating time during
which a deviation occurred, the date, time and length of time that
deviations occurred, and the corrective actions taken and any
preventative measures adopted to operate the device within that
operating parameter;
    (iv) Records of any instances in which the pilot flame is not
present, electronically controlled automatic igniter is not
functioning, or the monitoring equipment is not functioning in the
enclosed combustor, the utility flare, or the pit flare, the date and
times of the occurrence, the corrective actions taken, and any
preventative measures adopted to prevent recurrence of the occurrence;
    (v) Records of any instances in which a recording device installed
to record data from the enclosed combustor, utility flare, or pit flare
is not operational; and
    (vi) Records of any time periods in which visible smoke emissions
are observed emanating from the enclosed combustor, utility flare, or
pit flare.
    (6) For each pit flare at an oil and natural gas production
facility, a demonstration of compliance with the use restrictions set
forth in Sec.  49.4165(d)(2)(ii) is made by keeping records in a log
book, or similar recording system, during each period of time that the
pit flare is operating. The records must contain the following
information:
    (i) Date and time the pit flare was started up and subsequently
shut down;
    (ii) Total hours operated when pipeline injection was temporarily
infeasible for the current calendar month plus the previous consecutive
eleven (11) calendar months; and
    (iii) Brief descriptions of the justification for each period of
operation.
    (7) Records of any instances in which any closed-vent system or
control device was bypassed or down, the

reason for each incident, its duration, the volume of natural gas
emissions released, and the corrective actions taken and any
preventative measures adopted to avoid such bypasses or downtimes; and
    (8) Documentation of all produced oil storage tank and produced
water storage tank inspections required in Sec.  49.4166(e) and (f).
All inspection records must include, at a minimum, the following
information:
    (i) The date of the inspection;
    (ii) The findings of the inspection;
    (iii) Any adjustments or repairs made as a result of the
inspections, and the date of the adjustment or repair; and
    (iv) The inspector's name and signature.
    (b) Each owner or operator must keep all records required by this
section onsite at the facility or at the location that has day-to-day
operational control over the facility and must make the records
available to the EPA upon request.
    (c) Each owner or operator must retain all records required by this
section for a period of at least five (5) years from the date the
record was created.

Sec.  49.4168  Notification and reporting requirements.

    (a) Each owner or operator must submit any documents required under
this section to: U.S. Environmental Protection Agency, Region 8 Office
of Enforcement, Compliance & Environmental Justice, Air Toxics and
Technical Enforcement Program, 8ENF-AT, 1595 Wynkoop Street, Denver,
Colorado 80202. Documents may be submitted electronically to
<EMAIL_ADDRESS>    (b) Each owner and operator must submit an annual report containing
the information specified in paragraphs (b)(1) through (4) of this
section. Each annual report is due August 15th every year and must
cover all information for the previous calendar year. The initial
report must cover the cumulative information for that year. If you own
or operate more than one oil and natural gas production facility, you
may submit one report for multiple oil and natural gas production
facilities provided the report contains all of the information required
as specified in paragraphs (b)(1) through (4) of this section. Annual
reports may coincide with title V reports as long as all the required
elements of the annual report are included. The EPA may approve a
common schedule on which reports required by Sec. Sec.  49.4161 through
49.4168 may be submitted as long as the schedule does not extend the
reporting period.
    (1) The company name and the address of the oil and natural gas
production facility or facilities.
    (2) An identification of each oil and natural gas production
facility being included in the annual report.
    (3) The beginning and ending dates of the reporting period.
    (4) For each oil and natural gas production facility, the
information in paragraphs (b)(4)(i) through (iv) of this section.
    (i) A summary of all required records identifying each oil and
natural gas well completion or recompletion operation for each oil and
natural gas production facility conducted during the reporting period;
    (ii) An identification of the first date of production for each oil
and natural gas well at each oil and natural gas production facility
that commenced production during the reporting period; and
    (iii) A summary of cases where construction or operation was not
performed in compliance with the requirements specified in Sec.
49.4164, Sec.  49.4165, or Sec.  49.4166 for each oil and natural gas
well at each oil and natural gas production facility, and the
corrective measures taken.
    (iv) A certification by a responsible official of truth, accuracy
and completeness. This certification shall state that, based on
information and belief formed after reasonable inquiry, the statements
and information in the document are true, accurate and complete.
[FR Doc. 2013-05666 Filed 3-21-13; 8:45 am]
BILLING CODE 6560-50-P


[Federal Register Volume 85, Number 84 (Thursday, April 30, 2020)]
[Notices]
[Page 23968]
[FR Doc No: 2020-09168]

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DEPARTMENT OF HEALTH AND HUMAN SERVICES

Food and Drug Administration

[Docket No. FDA-2017-N-6644]

Fiscal Year 2020 Generic Drug Regulatory Science Initiatives;
Public Workshop; Remote Only

AGENCY: Food and Drug Administration, HHS.

ACTION: Notice.

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

SUMMARY: The Food and Drug Administration is announcing that the
following public workshop entitled ``FY 2020 Generic Drug Regulatory
Science Initiatives'' announced in the Federal Register on March 10,
2020, is being modified to take place remotely.

DATES: The public workshop will be held on May 4, 2020, from 8:30 a.m.
to 4:30 p.m. Submit either electronic or written comments on this
public workshop by June 4, 2020. See the SUPPLEMENTARY INFORMATION
section for registration and participation information.

FOR FURTHER INFORMATION CONTACT: Stephanie Choi, Center for Drug
Evaluation and Research, Food and Drug Administration, 10903 New
Hampshire Ave., Bldg. 75, Rm. 4732, Silver Spring, MD 20993-0002, 240-
402-7960<EMAIL_ADDRESS>or Robert Lionberger, Center for
Drug Evaluation and Research, Food and Drug Administration, 10903 New
Hampshire Ave., Bldg. 75, Rm. 4722, Silver Spring, MD 20993, 240-402-
7957<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION: Due to the ongoing COVID-19 pandemic, this
workshop announced in the Federal Register on March 10, 2020 (85 FR
13905) is being changed from in person to remote only. How to register
and participate in this remote meeting will be communicated on the FDA
web page at the following address: https://www.fda.gov/news-events/fda-meetings-conferences-and-workshops/fy-2020-generic-drug-regulatory-science-initiatives-public-workshop-05042020-05042020.

    Dated: April 24, 2020.
Lowell J. Schiller,
Principal Associate Commissioner for Policy.
[FR Doc. 2020-09168 Filed 4-29-20; 8:45 am]
BILLING CODE 4164-01-P