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 Production
Facilities, Fort Berthold Indian Reservation (Mandan, Hidatsa and
Arikara Nations)''.
    (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.  49.140 through 49.147 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 Production Facilities, Fort
Berthold Indian Reservation (Mandan, Hidatsa and Arikara Nations)'' 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 Production Facilities, Fort Berthold Indian
Reservation (Mandan, Hidatsa and Arikara Nations)'' 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 Nations)'' 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 Nations)'' 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 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 Production Facilities, Fort Berthold Indian Reservation
(Mandan, Hidatsa and Arikara Nations)'' 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.  49.143  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.  49.144
and Sec.  49.145.
    (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.  49.144 and Sec.  49.145.
    (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.  49.144 and Sec.  49.145.
    (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.
49.144(c) and Sec.  49.145.
    (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 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.  49.144 and Sec.  49.145.
    (f) Produced oil storage tanks and any produced water storage tanks
interconnected with produced oil storage tanks subject to and
controlled under the requirements specified in 40 CFR part 60, subpart
OOOO are considered to meet the requirements of

Sec.  49.143(d)(2). No further requirements apply for such storage
tanks under Sec.  49.143(d)(2).

Sec.  49.144  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
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 one of the 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.
    (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.  49.140 through 49.147
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.  49.147(b); or
    (ii) Demonstrated to meet the VOC destruction efficiency
requirements of Sec. Sec.  49.140 through 49.147 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.  49.147(b); or
    (iii) Until such time that 40 CFR part 60, subpart OOOO is
promulgated, demonstrated to meet the VOC destruction efficiency
requirements of Sec. Sec.  49.140 through 49.147 by using the EPA
approved performance test methods specified in 40 CFR part 63, subpart
HH at Sec.  63.772(e)(1)(i) through (iii) for hazardous air pollutants,
by the due date of the first annual report as specified in Sec.
49.147(b).
    (6) The owner or operator must ensure that each enclosed combustor
and utility flare is:
    (i) Operated properly at all times that natural gas is 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, a thermocouple, and a
malfunction alarm and remote notification system if the pilot flame
fails.
    (B) An electronically controlled auto-ignition system with a
malfunction alarm and remote notification system if the pilot flame
fails while produced natural gas or natural gas emissions are flowing
to the enclosed combustor or utility flare;
    (v) Equipped with a continuous recording device, such as a chart
recorder, data logger or similar device, or connected to a Supervisory
Control and Data Acquisition (SCADA) system, to monitor and document
proper operation of the enclosed combustor or utility flare;
    (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 natural gas emissions in the event that natural gas
recovered for pipeline injection must be diverted to an emergency
control device because injection is temporarily infeasible and the
enclosed combustor or utility flare installed at the oil and natural
gas production facility is not operational. Use of the pit flare for
this situation is limited to a maximum of 500 hours in any twelve (12)
consecutive months during periods when pipeline injection has become
temporarily infeasible and no enclosed combustor or utility flare
installed at the facility is operational; 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
auto-ignition system with a malfunction alarm and remote notification
system if the pilot flame fails;
    (v) The pit flare is visually inspected for the presence of a pilot
flame anytime produced natural gas or natural gas emissions are being
routed to it. Should the pilot flame fail, the flame must be relit as
soon as safely possible and the electronically controlled auto-ignition
system 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 written approval by the EPA, the
owner or operator may use control devices other than those listed above
that are 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.  49.145  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 US 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 natural gas emissions in the event that
natural gas recovered for pipeline injection must be diverted to an
emergency control device because injection is temporarily infeasible
and the enclosed combustor or utility flare installed at the oil and
natural gas production facility is not operational.
    (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 the enclosed combustor, utility flare, and
pit flare operation, using a malfunction alarm and remote notification
system for failures, and checking the system for proper operation
whenever an operator is on site, at a minimum quarterly;
    (2) Continuously monitor all variable operational parameters
specified in the written operating instructions and procedures;
    (3) Using EPA Reference Method 22 of 40 CFR part 60, Appendix A,
confirm that no visible smoke emissions are present, except for periods
not to exceed a total of 2 minutes during any hour, during operation of
any enclosed combustor, utility flare, or pit flare whenever an
operator is on site; at a minimum quarterly. The observation period
shall be 1 hour; and
    (4) Respond to any observation of improper monitoring equipment
operation or any pilot flame failure alarm and ensure the monitoring
equipment is returned to proper operation and/or the pilot flame is
relit 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.  49.145 and Sec.  49.146, the owner or operator
may use a

Supervisory Control and Data Acquisition (SCADA) system to monitor and
record the required data in Sec. Sec.  49.140 through 49.147.

Sec.  49.146  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) For each oil and natural gas well completion operation and
recompletion operation at an oil and natural gas production facility:
    (i) Records identifying each oil and natural gas well completion
operation and recompletion operation for each oil and natural gas
production facility; and
    (ii) The latitude and longitude location of the oil and natural gas
well; the date, time, and duration of flowback from the oil and natural
gas well; the date, time, and duration of any venting of produced
natural gas from the oil and natural gas well; and specific reasons for
each instance of venting in lieu of capture or combustion. The duration
must be specified in hours.
    (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 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.  49.144(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, 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.  49.145(d) and (e). 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.  49.147  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. The annual report must cover the period for the previous
calendar year. The initial annual report is due 1 year after the first
date of production for the first oil and natural gas well at each oil
and natural gas production facility or 1 year after August 15, 2012,
whichever is later. Subsequent annual reports are due on the same date
each year as the initial annual report. 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.  49.140 through 49.147 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 (iii) 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.
49.143, Sec.  49.144, or Sec.  49.145 for each oil and natural gas well
at each oil and natural gas production facility, and the corrective
measures taken.

[FR Doc. 2012-19698 Filed 8-14-12; 8:45 am]
BILLING CODE 6560-50-P


[Federal Register: October 17, 2008 (Volume 73, Number 202)]
[Notices]
[Page 61852-61853]
[DOCID:fr17oc08-75]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Docket No. ER09-33-000]

Barton Windpower II, LLC; Supplemental Notice That Initial
Market-Based Rate Filing Includes Request for Blanket Section 204
Authorization

October 10, 2008.
    This is a supplemental notice in the above-referenced proceeding of
Barton Windpower II, LLC's application for market-based rate authority,
with an accompanying rate tariff, noting that such application includes
a request for blanket authorization, under 18 CFR part 34, of future
issuances of securities and assumptions of liability.
    Any person desiring to intervene or to protest should file with the
Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426, in accordance with Rules 211 and 214 of the
Commission's Rules of Practice and Procedure (18 CFR 385.211 and
385.214). Anyone filing a motion to intervene or protest must serve a
copy of that document on the Applicant.
    Notice is hereby given that the deadline for filing protests with
regard to the applicant's request for blanket authorization, under 18
CFR part 34, of future issuances of securities and assumptions of
liability, is October 30, 2008.
    The Commission encourages electronic submission of protests and
interventions in lieu of paper, using the FERC Online links at http://
www.ferc.gov. To facilitate electronic service, persons with Internet
access who will eFile a document and/or be listed as a contact for an
intervenor must create and validate an eRegistration account using the
eRegistration link. Select the eFiling link to log on and submit the
intervention or protests.
    Persons unable to file electronically should submit an original and
14 copies of the intervention or protest to the Federal Energy
Regulatory Commission, 888 First St., NE., Washington, DC 20426.
    The filings in the above-referenced proceeding are accessible in
the

Commission's eLibrary system by clicking on the appropriate link in the
above list. They are also available for review in the Commission's
Public Reference Room in Washington, DC. There is an eSubscription link
on the Web site that enables subscribers to receive e-mail notification
when a document is added to a subscribed dockets(s). For assistance
with any FERC Online service, please e-mail<EMAIL_ADDRESS>
or call<PHONE_NUMBER> (toll free). For TTY, call<PHONE_NUMBER>.

Kimberly D. Bose,
Secretary.
 [FR Doc. E8-24663 Filed 10-16-08; 8:45 am]

BILLING CODE 6717-01-P


[Federal Register Volume 84, Number 131 (Tuesday, July 9, 2019)]
[Notices]
[Pages 32763-32764]
[FR Doc No: 2019-14577]

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DEPARTMENT OF HOMELAND SECURITY

Federal Emergency Management Agency

[Internal Agency Docket No. FEMA-4414-DR; Docket ID FEMA-2019-0001]

Minnesota; Amendment No. 1 to Notice of a Major Disaster
Declaration

AGENCY: Federal Emergency Management Agency, DHS.

ACTION: Notice.

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SUMMARY: This notice amends the notice of a major disaster declaration
for State of Minnesota (FEMA-4414-DR), dated February 1, 2019, and
related determinations.

DATES: This change occurred on June 13, 2019.

FOR FURTHER INFORMATION CONTACT: Dean Webster, Office of Response and
Recovery, Federal Emergency Management Agency, 500 C Street SW,
Washington, DC 20472,<PHONE_NUMBER>.

SUPPLEMENTARY INFORMATION: The Federal Emergency Management Agency
(FEMA) hereby gives notice that pursuant to the authority vested in the
Administrator, under Executive Order 12148, as amended, John F. Boyle,
of FEMA is appointed to act as the Federal Coordinating Officer for
this disaster.
    This action terminates the appointment of Steven W. Johnson as
Federal Coordinating Officer for this disaster.

    The following Catalog of Federal Domestic Assistance Numbers
(CFDA) are to be used for reporting and drawing funds: 97.030,
Community Disaster Loans; 97.031, Cora Brown Fund; 97.032, Crisis
Counseling;

97.033, Disaster Legal Services; 97.034, Disaster Unemployment
Assistance (DUA); 97.046, Fire Management Assistance Grant; 97.048,
Disaster Housing Assistance to Individuals and Households in
Presidentially Declared Disaster Areas; 97.049, Presidentially
Declared Disaster Assistance--Disaster Housing Operations for
Individuals and Households; 97.050, Presidentially Declared Disaster
Assistance to Individuals and Households--Other Needs; 97.036,
Disaster Grants--Public Assistance (Presidentially Declared
Disasters); 97.039, Hazard Mitigation Grant.

Pete Gaynor,
Acting Administrator, Federal Emergency Management Agency.
[FR Doc. 2019-14577 Filed 7-8-19; 8:45 am]
 BILLING CODE 9111-23-P