Basin Emissions Inventory. Assuming that the annualized cost to install
a vapor capture line to an existing combustor is similar to that of
routing pneumatic pumps to a combustor (approximately $1,627 per
source) and assuming there are approximately 2,100 sources that would
be required to add a combustor, such a requirement would result in high
costs relative to the VOC emissions reductions that would be achieved.
    Concerning pneumatic controllers, this proposed U&O FIP
requirements for pneumatic controllers require owners/operators of
affected pneumatic controllers to meet the standards established for
pneumatic controllers in NSPS OOOO and OOOOa. We are proposing that
owners/operators of affected controllers meet the tagging requirements
in 40 CFR 60.5390(b)(2), 60.5390(c)(2) and 60.5390a(b)(2) and (c)(2),
except that the month and year of installation, reconstruction or
modification is not required. This exception is consistent with the
Utah Oil and Gas Rules.
    Lastly, for existing enclosed combustors, utility flares, or other
open flares present at sources that would not be required to comply
with the substantive VOC emissions control requirements of proposed
sections Sec. Sec.  49.4174 through 49.4178, we are proposing to
require that those voluntarily operated control devices be equipped
with an electronically controlled automatic ignition device. This
approach is the same as the requirements of the Utah Oil and Gas Rules,
which require automatic igniters on all existing combustion devices.
Contrary to the proposed requirements in Section 49.4179 (VOC Emission
Control Devices) for devices used to comply with the substantive VOC
emissions control requirements of this proposed U&O FIP, we determined
that requiring a system to monitor proper operation of devices used to
ensure the presence of a flame at all times a gas stream is routed to
the device was unreasonable for voluntarily operated devices and would
result in requirements for such sources on the U&O Reservation that are
not comparable to requirements for such sources on lands regulated by
the UDEQ.

G. Monitoring Requirements

    For new, modified, and existing sources, we are proposing in Sec.
49.4183 (Monitoring Requirements) to require each owner or operator to
conduct source monitoring necessary for the practical enforceability of
all of this proposed U&O FIP's VOC emission reduction requirements,
including: (1) Monthly inspections of each closed-vent system,
including storage tank openings, thief hatches, and bypass devices, for
defects that can result in air emissions according to the procedures in
40 CFR 60.5416(c) [NSPS OOOO]; (2) monthly auditory, visual, olfactory
(AVO) inspections of each VOC emissions control device, tank thief
hatch, cover, seal, pressure relief valve, and closed-vent system to
ensure proper condition and functioning, performed while the storage
tanks are being filled, and corrective action within 5 days of
discovering the device is not operational; and (3) monitoring of each
enclosed combustor or utility flare to confirm proper operation as
follows: By checking the system for proper operation whenever an
operator is onsite and responding to any indication of pilot flame
failure and to ensure the pilot flame is relit as soon as practically
and safely possible; and (4) monitoring of visible emissions according
to the requirements in 40 CFR 60.5412(d)(i)(iii) [NSPS OOOO, which
requires EPA Method 22 visual emissions testing].
    These proposed monitoring requirements are comparable on balance
with those in the Utah Permit Requirements and Utah Oil and Gas Rules,
with some exceptions made to ensure legally and practicably enforceable
control of VOC emissions.
    For example, the Utah Permit Requirements and Utah Oil and Gas
Rules require installation and operation of an automatic ignition
device and operations with no visible emissions for all VOC control
devices, but there are no corresponding monitoring requirements to
demonstrate compliance with those requirements. We expect that the
proposed monitoring requirements for ensuring there is a constant
ignition source when gas is flowing to the control device and for
visible emissions testing will provide legal and practical
enforceability.
    We are seeking comment on the monitoring requirements in this
proposed U&O FIP, including information supporting more or less
stringent monitoring requirements that would provide legal and
practical enforceability of the proposed VOC emission control
requirements.

H. Recordkeeping Requirements

    For new, modified and existing sources, we are proposing in Sec.
49.4184 (Recordkeeping Requirements) to require that each owner or
operator of an affected oil and natural gas source keep specific
records to be made available upon request, in lieu of voluminous
reporting requirements. The records that must be kept include all
required measurements, monitoring results, emissions calculations, 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 for the control and emission reduction
requirements of this rule.
    We are seeking comment on the recordkeeping requirements in this
proposed U&O FIP, including

information supporting more or less stringent recordkeeping
requirements that would provide legal and practical enforceability of
the proposed VOC emission control requirements.

I. Notification and Reporting Requirements

    For new, modified, and existing sources, we are proposing in Sec.
49.4185 (Reporting Requirements) to require that each owner or operator
of an affected oil and natural gas source prepare and submit an annual
compliance report, beginning 90 days after the end of the first
compliance reporting period, which is one year after this rule becomes
effective and covers the period for the previous calendar year. The
report must include a summary of required records and a summary of
deviations or exceedances of any requirements of the final FIP and the
corrective measures taken. Additionally, a report of results must be
submitted for any performance test we require. These reporting
requirements provide legal and practical enforceability for the control
and emission reduction requirements of this rule. We are seeking
comments on the reporting frequency in this proposed U&O FIP, including
information supporting a more or less frequent reporting schedule.

VI. Statutory and Executive Order Reviews

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

    This proposed action is an economically significant regulatory
action and was submitted to the Office of Management and Budget (OMB)
for review. Any changes made in response to the OMB recommendations
have been documented in the docket. The EPA prepared an analysis of the
potential costs and benefits associated with this proposed action. This
analysis, ``Regulatory Impact Analysis of for the Proposed Federal
Implementation Plan for Managing Emissions from Oil and Natural Gas
Sources on Indian Country Lands Within the Uintah and Ouray Indian
Reservation in Utah'' (Ref. EPA-908/Z-16-001), is available in the
docket, and is summarized in Section IV.I. Benefits and Costs of the
Proposed Rule.

B. Executive Order 13771: Reducing Regulations and Controlling
Regulatory Costs

    This action is expected to be an Executive Order 13771 regulatory
action. Details on the estimated costs of this proposed rule can be
found in the EPA's analysis of the potential costs and benefits
associated with this action.

C. Paperwork Reduction Act (PRA)

    The information collection activities in this proposed rule have
been submitted to the Office of Management and Budget (OMB) for
approval under the PRA. The Information Collection Request (ICR)
document that the EPA is preparing for this proposed U&O FIP has been
assigned EPA ICR number 2539.01. You can find a copy of the ICR in the
docket for this rule, and it is briefly summarized here.
    This proposed action imposes a new information collection burden
under the PRA. The ICR covers information collection necessary to meet
the requirements in this proposed U&O FIP. In general, owners or
operators are required to maintain records of all required monitoring
and other rule compliance. This proposed U&O FIP also requires annual
reports containing information for each oil and natural gas source,
including a summary of all required records during the reporting
period, and a summary of all instances where operation was not
performed in compliance with the requirements of this proposed U&O FIP
during the reporting period. Additionally, a summary emissions
inventory is required for each source covered under this rulemaking
once every three years. These reports and records are essential in
determining compliance and are required of all sources subject to this
proposed U&O FIP. The information collected will be used by the EPA or
the Ute Indian Tribe to determine the compliance status of sources
subject to the rule.
    Respondents/affected entities: The potential respondents are owners
or operators of existing, new, and modified oil and natural gas sources
on Indian country lands within the U&O Reservation.
    Respondent's obligation to respond: Mandatory. The EPA is charged
under sections 301(a) and 301(d)(4) of the CAA to promulgate
regulations as necessary to protect tribal air resources. Promulgating
this proposed U&O FIP would address winter ozone air quality
concentrations that exceed the NAAQS, and given the recent ozone NAAQS
nonattainment designation, when combined with the National O&NG FIP
amendments, would provide justification to allow continued streamlined
construction authorization of new or modified true minor oil and
natural gas sources, all in a manner that seeks to provide regulatory
consistency between state and federal requirements with regard to
controlling VOC emissions from existing, new, and modified oil and
natural gas operations on the U&O Reservation. There is no other
federal rule, including the recently finalized NSPS and NESHAP for the
Oil and Natural Gas Sector (NSPS OOOO, NSPS OOOOa, and NESHAP HH), that
establishes air pollution control regulations for the particular oil
and natural gas operations that exist on the U&O Reservation that are
appropriate to address the issues identified for this area. This is in
contrast to oil and natural gas operations on non-Indian-country lands
under the State of Utah's jurisdiction, which are governed by the UDEQ
regulations and Utah Division of Oil, Gas, and Mining regulations.
Consistent with the regulatory structure that exists on non-Indian
country lands, this proposed U&O FIP has requirements for VOC emissions
control and reductions, monitoring, recordkeeping, and reporting.
    In addition, section 114(a) states that the Administrator may
require any owner or operator subject to any requirement of this Act
to:
     Establish and maintain such records;
     Make such reports;
     Install, use, and maintain such monitoring equipment, and
use such audit procedures, or methods;
     Sample such emissions (in accordance with such procedures
or methods, at such locations, at such intervals, during such periods,
and in such manner as the Administrator shall prescribe);
     Keep records on control equipment parameters, production
variables or other indirect data when direct monitoring of emissions is
impractical;
     Submit compliance certifications in accordance with
section 114(a)(3); and
     Provide such other information as the Administrator may
reasonably require.
    Estimated number of respondents: We estimate that 4,894 oil and
natural gas sources will be subject to one or more requirements in this
proposed U&O FIP over the next three years.
    Frequency of response: Annual reports are required. Respondents
must monitor all specified criteria at each affected source and
maintain these records for five years.
    Total estimated burden: 123,000 hours per year (3-year average),
for all operators subject to this proposed U&O FIP.
    Total estimated cost: $21.6 million per year; includes labor cost
of $6.4 million, annualized capital cost of $6.4 million, and $8.7
million in operation and maintenance costs for all of the

operators that would subject to this proposed U&O FIP.
    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 the
EPA's regulations in 40 CFR are listed in 40 CFR part 9.
    Submit your comments to the EPA on the Agency's need for this
information, the accuracy of the provided burden estimates and any
suggested methods for minimizing respondent burden, using the docket
identified at the beginning of this proposed rule. You may also send
your ICR-related comments to OMB's Office of Information and Regulatory
Affairs via email to<EMAIL_ADDRESS>Attention: Desk
Officer for the EPA. Since OMB is required to make a decision
concerning the ICR between 30 and 60 days after receipt, OMB must
receive comments no later than 30 days after publication of the ICR in
the Federal Register. The EPA will respond to any ICR-related comments
in the final rule.

D. Regulatory Flexibility Act (RFA)

    I certify that this action will not have a significant economic
impact on a substantial number of small entities under the RFA. The
small entities subject to the requirements of this action are owners/
operators of oil and natural gas sources on the U&O Reservation. They
were identified through a review of existing minor source registrations
submitted by owners/operators on the U&O Reservation under the Federal
Indian Country Minor NSR rule. The Agency has determined that two out
of eleven total small entities, or 18%, may experience an impact of 0%
to 3% of revenues.\131\
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    \131\ The RIA includes a more detailed analysis of the impact of
the proposed rule to small entities. It can be viewed in the docket
for this rulemaking (Docket ID No. EPA-R08-OAR-2015-0709).
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E. Unfunded Mandates Reform Act (UMRA)

    This proposed action does not contain an unfunded mandate of $100
million of more as described in UMRA, 2 U.S.C. 1531-1538, and does not
significantly or uniquely affect small governments. This action imposes
no enforceable duty on any state, local or tribal governments, and the
action contains a federal private sector mandate that may result in the
expenditures of less than $100 million for the private sector in any
one year.
1. Statutory Authority
    The legal authority for this rule stems from sections 301(a) and
301(d)(4) of the CAA and 40 CFR 49.11(a). See section III.B of this
preamble for more information.
2. Costs and Benefits
    As discussed in Section IV.I. Benefits and Costs of the Proposed
Rule, the estimated total annualized engineering costs of this proposed
rule in 2021, accounting for the recovered natural gas, are $64 million
in 2016 dollars using a 7 percent discount rate and $56 million in 2021
in 2016 dollars using a 3 percent discount rate.\132\ The EPA estimates
that the proposed rule will lead to annual monetized benefits of about
$10 million in 2021 using a 3 percent discount rate and $2.9 million at
a 7 percent discount rate. Including the resources from recovered
natural gas that would otherwise be vented, the quantified annualized
net benefits of the regulation (the difference between the monetized
benefits and total annualized compliance costs) are estimated to be -
$39 million in 2021 in 2016 dollars using a 3 percent interest rate and
-$46 million using a 7 percent interest rate.\133\ More in-depth
information on costs and benefits, including non-monetized or
quantified benefits, of the final regulation can be found in the
RIA.\134\ We are seeking comment on the cost assumptions used in our
RIA, including comments and information supporting higher or lower cost
estimates. Specifically, the EPA is requesting comment on the capital
costs of routing a glycol dehydrator and/or pneumatic pump to an
existing combustor.
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    \132\ The recordkeeping and reporting costs calculated for the
ICR analysis, discussed earlier, are imbedded in the total
annualized engineering costs included here.
    \133\ The RIA in the docket for this rulemaking discusses this
calculation in detail.
    \134\ The RIA includes a more detailed discussion of the
potential costs and benefits associated with this rule. It can be
viewed in the docket for this rulemaking (Docket ID No. EPA-R08-OAR-
2015-0709).
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3. Effects on National Economy
    The EPA estimated the labor impacts due to compliance with the
proposed rule for affected entities within the oil and natural gas
sector, including the installation, operation, and maintenance of
control equipment and control activities, as well as the labor
associated with new reporting and recordkeeping requirements. We did
not estimate any potential changes in labor outside of the affected
sector, and due to data and methodology limitations we did not estimate
net employment impacts for the affected sector, apart from the partial
estimate of the labor requirements related to control strategies. The
labor requirements analysis used a bottom-up engineering-based
methodology to estimate employment impacts. The engineering cost
analysis of the RIA includes estimates of the labor requirement costs
associated with implementing the regulations. Each of these labor
changes may be required as part of an initial effort to comply with the
new regulation.
4. Regulatory Alternatives
    Alternate regulatory options examined in the RIA include a low-
impact option (Option 1) and a high-impact option (Option 3). The
Option 1 requirements would be like Option 2; however, they would not
include control of emissions from glycol dehydrators. Additionally,
Option 1 would require implementation of LDAR at sources with a gas-to-
oil ratio (GOR) of greater than or equal to 300, that produce on
average, greater than 15-barrel equivalents per well per day. This is
in contrast to proposed Option 2, which would require implementation of
an LDAR program at sources that are required to control storage tank,
glycol dehydrator, and pneumatic pump VOC emissions per proposed
Sec. Sec.  49.4173 through 49.4177. The EPA could have considered a
range of even less stringent regulatory options than Option 1 to
evaluate and propose, including an option that would not require
retrofit of existing storage tanks with controls or requires controls
less broadly. Retrofitting existing tanks with controls is one of the
higher costs evaluated in this proposed rulemaking. Such an option,
however, would lead to even greater disparity with the requirements for
similar sources in Utah jurisdiction in the Basin than the current
Option 1. However, we are seeking comment on whether it is appropriate
to consider a less stringent option that does not include retrofitting
existing storage tanks for controls, recognizing that if comments
support it as a viable regulatory option and if the agency proposes to
adopt that option, the EPA may be required to hold an additional public
comment period on this rulemaking. Option 3 (high impact) would require
implementation of an LDAR program at all existing oil and natural gas
sources, regardless of throughput, or tank, dehydrator, and pneumatic
pump annual VOC emissions.
    This proposed U&O FIP results in estimated annualized costs of $60
million in 2021 using a 3 percent

interest rate, resulting in a cost of control of $3,000 per ton of the
estimated 20,000 tons of VOC reduced, and -annualized costs of $68
million using a 7 percent interest rate, resulting in a cost of control
of $3,400 per ton of the estimated 20,000 tons of VOC reduced.
    The annualized costs of the first option (Option 1) would be $43
million in 2021 using a 7 percent discount rate, resulting in a cost of
control of $3,300 per ton of the estimated 13,000 tons of VOC reduced,
and $38 million in 2021 using a 3 percent discount rate, resulting in a
cost of control of $2,900 per ton of VOC reduced. Option 1 was analyzed
to reduce burden on small entities, while still achieving VOC emissions
reductions. Although this option would cost less overall than proposed
Option 2, it would achieve significantly less benefits in the form of
VOC emissions reductions (13,000 tons versus 20,000 tons for proposed
Option 2), because emissions from glycol dehydrators would not be
controlled and a smaller number of storage tanks would be controlled,
because the VOC emissions threshold triggering control would be
different than Option 2.\135\ Additionally, by not controlling glycol
dehydrator emissions in Option 1, there would also be significantly
less benefits from the associated reductions in HAP emissions that are
more reactive in forming ozone than the lighter-end VOC emissions
resulting from storage tanks, pneumatic pumps and fugitive emissions.
Implementation of Option 1 would also lead to regulatory requirements
that are inconsistent with the requirements for equivalent sources in
UDEQ jurisdiction, thus not meeting our goal of regulatory consistency
across the Uinta Basin.
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    \135\ Under Option 1, the EPA would determine the four tpy
threshold triggering control with combined source-wide VOC emissions
from storage tanks and pneumatic pumps only.
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    The annualized costs of Option 3 would be $79 million in 2021 using
a 7 percent discount rate, resulting in a cost of control of $3,500 per
ton of the estimated 23,000 tons of VOC reduced, and $71 million in
2021 using a 3 percent discount rate, resulting in a cost of control of
$3,100 per ton of VOC reduced. Option 3 was analyzed to achieve a
greater level of VOC emissions reductions. Although this option would
achieve about 3,000 more tons of VOC emissions reductions than proposed
Option 2, it would also result in increases in costs. Additionally,
Option 3 would lead to regulatory requirements that are inconsistent
with the requirements for equivalent sources in UDEQ jurisdiction, thus
not meeting our goal of regulatory consistency across the Uinta Basin.
    For a more in-depth analysis of these options, see the RIA for this
proposed U&O FIP.

F. Executive Order 13132: Federalism

    This proposed 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.

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

    This proposed action has tribal implications. However, it will
neither impose substantial direct compliance costs on federally
recognized tribal governments, nor preempt tribal law. The EPA has
conducted outreach on this proposed rule consistent with the EPA Policy
on Consultation and Coordination with Indian Tribes (May 4, 2011) via
ongoing monthly meetings with tribal environmental professionals \136\
before and during the development of this proposed action, and further
as follows: (1) Via Tribal consultation with the Ute Indian Tribe
Business Committee regarding options that the EPA could consider to
address the Uinta Basin air quality concerns; (2) via stakeholder
meetings where the Tribe was included and participated in emissions
contributions discussions specific to the EPA's strategy for addressing
the Uinta Basin air quality concerns; and (3) via ongoing stakeholder
working group meetings convened by the Ute Indian Tribe Business
Committee where the EPA participated in discussions with the Tribe and
industrial operators on strategies to reduce existing ozone-related
emissions and provide a streamlined construction authorization
mechanism for new and modified minor oil and natural gas sources given
the recent nonattainment designation for the 2015 ozone NAAQS.
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    \136\ These monthly meetings are general in nature, dealing with
many air-related topics, and are not specific to this proposed U&O
FIP.
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    The EPA held consultations with elected officials of the Ute Indian
Tribe Business Committee on the following dates: July 22, 2015;
December 17, 2016; November 13, 2017; March 22, 2018, August 17, 2018;
November 14, 2018; and February 28, 2019. The EPA has also participated
in tribally convened stakeholder meetings on March 22, 2017 and June 1-
2, 2017.
    During the consultation discussions on this proposed U&O FIP, the
Tribe expressed concerns regarding their economic needs to develop and
generate revenue from Tribal oil and natural gas resources; to consider
air quality effects on the health, safety, and welfare concerns of
their tribal membership living within the exterior boundaries of the
U&O Reservation and the Uinta Basin; and to balance regulatory
requirements for an even economic and regulatory playing field.\137\ We
addressed questions the Tribe had regarding the controls being
considered, the ability for owners or operators to take credit for the
controls for purposes such as permitting and NAAQS attainment, the
estimated costs of proposed controls, the characterization of Indian
country, and the breadth of oil and natural gas source category types
proposed to be regulated. The Ute-Tribe-convened stakeholder meetings
involved discussions on appropriate ways to expedite nonattainment
permitting for new and modified minor oil and natural gas sources on
the U&O Reservation. Ute Indian Tribe and industry participants
recognized that existing source emissions reductions would likely be
necessary in order for the EPA to demonstrate that construction
authorization for new and modified sources would not cause or
contribute to NAAQS violations in the nonattainment area.
---------------------------------------------------------------------------

    \137\ The records of communication for all consultations and
preliminary discussions with the Ute Indian Tribe are included in
the docket for this rulemaking (Docket ID No. EPA-R08-OAR-2015-
0709).
---------------------------------------------------------------------------

    Enacting a FIP for the U&O Reservation is directly responsive to
the Ute Indian Tribe's air quality concerns in that we are proposing to
implement our CAA authority to protect air quality on and surrounding
Indian country lands within the U&O Reservation in a manner that
provides regulatory consistency with respect to requirements for oil
and natural gas sources on adjacent lands regulated by the state in the
Basin. We are committed to supporting tribes' right to self-governance
and to protecting their inherent sovereignty. We will continue to
provide outreach to tribal environmental professionals and continue
consultation with tribal leadership on this proposed action.

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

    This action is subject to Executive Order 13045 because it is an

economically significant regulatory action as defined by Executive
Order 12866 and the EPA has concluded that the environmental health or
safety risks addressed by this proposed action have a disproportionate
effect on children. This action's health and risk assessments are
contained in the Purpose, Air Quality Review, Benefits and Costs, and
Executive Order 12898: Federal Actions to Address Environmental Justice
in Minority Populations and Low Income Populations sections in this
preamble (sections II., IV.G., IV.I., and VI.J., respectively), with
more detailed information contained in the RIA for this
rulemaking.\138\ In fact, this proposed U&O FIP should have a positive
effect on the health of the residents of the U&O Reservation, including
children, as it is expected to result in a reduction in ambient ozone
concentrations, which disproportionately impact children, elderly, and
those with respiratory ailments.
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    \138\ The RIA includes more detailed discussions of the health
and risk assessments for this rule and can be viewed in the docket
for this rulemaking (Docket ID No. EPA-R08-OAR-2015-0709).
---------------------------------------------------------------------------

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

    This action is not a ``significant energy action'' as defined in
Executive Order 13211,\139\ because it is not likely to have a
significant adverse effect on the supply, distribution, or use of
energy. The basis for these determinations follows.
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    \139\ See 66 FR 28355 (May 22, 2001).
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    This proposed action was determined to be a significant regulatory
action that was submitted to the OMB for review under Executive Order
12866. Any changes made in response to the OMB recommendations have
been documented in the docket. The EPA prepared an analysis of the
potential costs and benefits associated with this proposed action,
which is included in the RIA,\140\ and is summarized in Section IV.I.
Benefits and Costs of the Proposed Rule.
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    \140\ The RIA includes a more detailed discussion of the
potential costs and benefits associated with this rule. It can be
viewed in the docket for this rulemaking (Docket ID No. EPA-R08-OAR-
2015-0709).
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    We have concluded that, while this action may have some effects on
the supply, distribution, or use of energy, it is not likely to have
significant adverse energy effects. Most owners/operators of existing
oil and natural gas production sources on the U&O Reservation also
operate sources on non-Indian country lands within and outside of the
U&O Reservation, where they are already required to employ the
emissions control technologies required by this proposed U&O FIP.
Additionally, we expect that these owners/operators will also operate
new and modified sources in the Uinta Basin that are subject to similar
NSPS OOOO and OOOOa, NESHAP HH, and other oil and natural gas sector-
related control requirements within the Uinta Basin. Therefore, it is
expected that the owners/operators will continue to procure necessary
control equipment and supplies from the same suppliers they currently
use for non-Indian country existing, new or modified sources. Further,
only the higher-producing sources are expected to be subject to the
more substantive emission control requirements in this proposed U&O
FIP, and those sources are more likely to be able to accommodate the
additional costs, so it is not expected that the new requirements alone
would factor significantly into decisions to slow or halt production
and thereby cause a shortfall in supply. Rather, the prices of oil and
natural gas are likely to be a more significant factor in decisions on
reducing production from existing sources, and prices are not expected
to change appreciably over from 2020 to 2025.\141\
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    \141\ The RIA includes more detailed information on oil and
natural gas prices. It can be viewed in the docket for this
rulemaking (Docket ID No. EPA-R08-OAR-2015-0709).
---------------------------------------------------------------------------

    Additionally, this proposed U&O FIP establishes several emissions
control standards that give regulated entities flexibility in
determining how to best comply with the regulation. Even within the
geographically and economically homogeneous affected area within the
Uinta Basin, this flexibility is an important factor in reducing
regulatory burden. For more information on the estimated energy effects
of the proposed rule, please see the RIA, which is in the docket for
this proposed rule.

J. National Technology Transfer and Advancement Act (NTTAA)

    Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (NTTAA), 15 U.S.C. 272 note, directs the EPA to use
voluntary consensus standards (VCS) in its regulatory activities unless
to do so would be inconsistent with applicable law or otherwise
impractical. VCS are technical standards, which include materials
specifications, test methods, sampling protocols, business practices
and management systems developed or adopted by voluntary consensus
standards bodies (VCSB), both domestic and international. These bodies
plan, develop, establish or coordinate voluntary consensus standards
using agreed-upon procedures.
    This action involves technical standards. Therefore, the EPA
conducted a search to identify potentially applicable VCS. However, the
Agency identified no such standards.\142\ Therefore, the EPA has
decided to use EPA Methods 21 and 22 of 40 CFR part 60, appendix A-7
and part 63, appendix A.\143\
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    \142\ ``Voluntary Consensus Standard Results for Federal
Implementation Plan for Managing Emissions from Oil and Natural Gas
Sources on the Uintah and Ouray Indian Reservation in Utah,''
Memorandum from Steffan Johnson, Group Leader, U.S. EPA, Measurement
Technology Group, to Deirdre Rothery, Unit Chief Air Permitting and
Monitoring Unit, U.S. EPA Region 8 Air Program, dated December 22,
2017, available in the Docket for this proposed rule (Docket ID No.
EPA-R08-OAR-2015-0709).
    \143\ The EPA Reference Methods 21 and 22 can be accessed at
https://www.ecfr.gov/cgi-bin/ECFR?page=browse (Search Title 40, Part
60 and Part 63, accessed August 21, 2019.
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K. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations

    The EPA concludes that this action does not have disproportionately
high and adverse human health or environmental effects on minority
populations, low-income populations, and/or indigenous peoples, as
specified in Executive Order 12898.\144\
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    \144\ See 59 FR 7629 (February 16, 1994).
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    The documentation for this decision is contained in the RIA \145\
for this proposed rule. Our objective in developing this proposed rule
is to protect the communities in and near Indian country lands within
the U&O Reservation, where existing oil and natural gas operations have
been shown to contribute to exceedances of the ozone NAAQS. The impacts
of this proposed rule are expected to be beneficial, rather than
adverse, and its benefits are expected to accrue to communities in and
near Indian country lands within the U&O Reservation. As explained in
Section IV.F., the EPA has quantified the expected emissions impacts
from this proposed action and found that the proposed action will
result in large reductions of VOC emissions.
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    \145\ The RIA includes a more detailed discussion of the
environmental justice analysis for this rule. It can be viewed in
the docket for this rulemaking (Docket ID No. EPA-R08-OAR-2015-
0709).
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    This proposed action will also provide regulatory certainty to
owners/operators, by imposing, to the extent

appropriate, requirements that are the same as or consistent with those
applicable to such existing sources that are regulated by the UDEQ in
the Uinta Basin because they are not on Indian country lands within the
Reservation. This will ensure that air quality is protected
consistently across the Uinta Basin and our Environmental Justice (EJ)
analysis that can be found in the RIA for this rulemaking supports the
conclusion that this action will not result in disproportionate
impacts.

List of Subjects in 40 CFR Part 49

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

    Dated: December 16, 2019.
Gregory Sopkin,
Regional Administrator, Region 8.
    For reasons set forth in the preamble, part 49 of title 40 of the
Code of Federal Regulations is proposed to be amended as follows:

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

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

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

0
2. Add the undesignated center heading ``Federal Implementation Plan
for Managing Emissions from Oil and Natural Gas Sources on the Indian
Country Lands Within the Uintah and Ouray Indian Reservation in Utah''
and Sec. Sec.  49.4169 through 49.4185 to subpart K to read as follows:
Subpart K--Implementation Plans for Tribes--Region VIII
* * * * *

Federal Implementation Plan for Managing Emissions From Oil and Natural
Gas Sources on the Indian Country Lands Within the Uintah and Ouray
Indian Reservation in Utah

Sec.
49.4169 Introduction.
49.4170 Delegation of authority of administration to the tribe.
49.4171 General provisions.
49.4172 Emissions inventory.
49.4173 Nonattainment requirements for new or modified true minor
oil and natural gas sources.
49.4174 VOC emissions control requirements for storage tanks.
49.4175 VOC emissions control requirements for dehydrators.
49.4176 VOC emissions control requirements for pneumatic pumps.
49.4177 VOC emissions control requirements for covers and closed-
vent system.
49.4178 VOC emissions control devices.
49.4179 VOC emissions control requirements for fugitive emissions.
49.4180 VOC emissions control requirements for tank truck loading.
49.4181 VOC emissions control requirements for pneumatic
controllers.
49.4182 Other combustion devices.
49.4183 Monitoring requirements.
49.4184 Recordkeeping requirements.
49.4185 Notification and reporting requirements.

Sec.  49.4169  Introduction.

    (a) What is the purpose of Sec. Sec.  49.4169 through 49.4185?
Sections 49.4169 through 49.4185 establish legally and practicably
enforceable requirements for oil and natural gas sources to address
ozone air quality. Section 49.4170 establishes provisions for
delegation of authority to allow the Ute Indian Tribe to assist the EPA
with administration of this proposed U&O FIP. Section 49.4171 contains
general provisions and definitions applicable to oil and natural gas
sources. Section 49.4173 establishes legally and practicably
enforceable requirements to control and reduce emissions of volatile
organic compounds (VOC), nitrogen oxides, sulfur dioxide, particulate
matter (PM, PM10 and PM2.5), hydrogen sulfide,
carbon monoxide and various sulfur compounds from new and modified true
minor oil and natural gas sources in the oil and natural gas production
and natural gas processing segments of the oil and natural gas sector
that are located on portions of the U&O Reservation that are included
in the Uinta Basin ozone nonattainment area and commence construction
on or after [30 DAYS AFTER DATE OF PUBLICATION OF THE FINAL RULE IN THE
FEDERAL REGISTER], unless the source obtains a site-specific
construction permit, or is otherwise required to obtain a site-specific
permit by the Reviewing Authority, in accordance with 40 CFR 49.151
through 49.161. Sections 49.4174 through 49.4185 establish legally and
practicably enforceable requirements to control and reduce VOC
emissions from oil and natural gas well production and storage
operations, natural gas processing, and gathering and boosting
operations at oil and natural gas sources (as defined in Sec.
49.4171(b)) that are located on Indian country lands within the U&O
Reservation.
    (b) Am I subject to Sec. Sec.  49.4169 through 49.4185? Sections
49.4169 through 49.4185, as appropriate, apply to each owner or
operator of an oil and natural gas source located on Indian country
lands within the U&O Reservation that has equipment or activities that
meet the applicability thresholds specified in each section. Generally,
the equipment and activities at oil and natural gas sources that are
already subject to and in compliance with VOC emission control
requirements under another EPA standard or other federally enforceable
requirement, as specified in each appropriate subsection later, are
considered to be in compliance with the requirements to control VOC
emissions from that same equipment under this proposed U&O FIP.
    (c) When must I comply with Sec. Sec.  49.4169 through 49.4185?
Compliance with Sec. Sec.  49.4169 through 49.4171 and 49.4174 through
49.4185, as applicable, is required no later than [DATE 18 MONTHS AFTER
DATE OF PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] for oil
and natural gas sources that commence construction before [DATE OF
PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER]. You may submit
a written request to the EPA for an extension of the compliance date
for existing sources that describes the specific reasons for the
requested extension. Any decision to approve or deny the request,
including the length of time of an approved request, will be based on
the determined merits of case-specific circumstances. Compliance with
Sec. Sec.  49.4169 through 49.4171 and 49.4174 through 49.4185, as
applicable, is required upon startup for oil and natural gas sources
that commence construction on or after [DATE OF PUBLICATION OF THE
FINAL RULE IN THE FEDERAL REGISTER]. Compliance with Sec.  49.4173 is
required upon commencing construction of any new and modified true
minor oil and natural gas source in the oil and natural gas production
and natural gas processing segments of the oil and natural gas sector
that is located on portions of the U&O Reservation that are included in
the Uinta Basin ozone nonattainment area that commences construction on
or after [30 DAYS AFTER DATE OF PUBLICATION OF THE FINAL RULE IN THE
FEDERAL REGISTER].

Sec.  49.4170  Delegation of authority of administration to the tribe.

    (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 Ute Indian Tribe the authority to assist the EPA
with administration of this proposed U&O 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 Ute Indian Tribe request delegation? In order to
be delegated authority to assist us with administration of this
proposed U&O FIP, the authorized representative of the Ute Indian Tribe
must submit a written request to the Regional Administrator that:
    (1) Identifies the specific provisions for which delegation is
requested;
    (2) Includes a statement by the Ute Indian Tribe's legal counsel
(or equivalent official) that includes the following information:
    (i) A statement that the Ute Indian Tribe is an Indian tribe
recognized by the Secretary of the Interior;
    (ii) A descriptive statement that meets the requirements of Sec.
49.7(a)(2) and demonstrates that the Ute Indian Tribe is currently
carrying out substantial governmental duties and powers over a defined
area;
    (iii) A description of the laws of the Ute Indian Tribe that
provide adequate authority to carry out the aspects of the rule for
which delegation is requested; and
    (3) Demonstrates that the Ute Indian Tribe has, 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 setting forth the terms and
conditions of the delegation and specifying the provisions of this rule
that the Ute Indian Tribe will be authorized to implement on behalf of
the EPA will be entered into by the Regional Administrator and the Ute
Indian Tribe. The Agreement will become effective upon the date that
both the Regional Administrator and the authorized representative of
the Ute Indian Tribe have signed the Agreement. Once the delegation
becomes effective, the Ute Indian Tribe will be responsible, to the
extent specified in the Agreement, for assisting us with administration
of the FIP and will 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 the FIP is to remain the EPA Regional Administrator
and when it is intended to refer to the ``Ute Indian Tribe,'' 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 Ute Indian Tribe.
    (d) How will any Delegation of Authority Agreement be publicized?
The Agency will publish a notice in the Federal Register informing the
public of any Delegation of Authority Agreement with the Ute Indian
Tribe to assist us with administration of all or a portion of the FIP
and identifying such delegation in the FIP. The Agency will also
publish an announcement of the Delegation of Authority Agreement in
local newspapers.

Sec.  49.4171  General provisions.

    (a) At all times, including periods of startup, shutdown, and
malfunction, each owner or operator must, to the extent practicable,
design, operate, and maintain all equipment used for hydrocarbon liquid
and gas collection, storage, processing, and handling operations
covered under Sec. Sec.  49.4171 and 49.4174 through 49.4185,
regardless of emissions rate and including associated air pollution
control equipment, in a manner that is consistent with good air
pollution control practices and that minimizes leakage of VOC emissions
to the atmosphere.
    (b) Definitions. As used in Sec. Sec.  49.4169 through 49.4185, all
terms not defined herein have the meaning given them in the Act, in 40
CFR part 60, 40 CFR part 63, in the Prevention of Significant
Deterioration regulations at 40 CFR 52.21, in the Federal Minor New
Source Review Program in Indian Country at 40 CFR 49.151, or in the
Federal Implementation Plan for Managing Air Emissions from True Minor
Sources in Indian Country in the Oil and Natural Gas Production and
Natural Gas Processing Segments of the Oil and Natural Gas Sector at 40
CFR 49.102. The following terms have the specific meanings given them:
    Bottom filling means the filling of a tank through an inlet at or
near the bottom of the tank designed to have the opening covered by the
liquid after the pipe normally used to withdraw liquid can no longer
withdraw any liquid.
    Condensate means hydrocarbon liquid separated from produced natural
gas that condenses due to changes in temperature, pressure, or both,
and that remains liquid at standard conditions.
    Crude oil means hydrocarbon liquids that are separated from well-
extracted reservoir fluids during oil and natural gas production
operations, and that are stored or injected to pipelines as a saleable
product. Condensate is not considered crude oil.
    Electronically controlled automatic ignition device means an
electronic device which generates sparks across an electrode and
reaches into a combustible gas stream traveling up a flare stack or
entering an enclosed combustor, at the point of the pilot tip, equipped
with a temperature monitor that signals the device to attempt to re-
light an extinguished pilot flame.
    Enclosed combustor means a thermal oxidation system with an
enclosed combustion chamber that maintains a limited constant
temperature by controlling fuel and combustion air.
    Flashing losses means natural gas emissions resulting from the
presence of dissolved natural gas in the crude oil, condensate, or
produced water, which are under high pressure that occurs as the
liquids are transferred to storage tanks that are at atmospheric
pressure.
    Fugitive emissions component means any component that has the
potential to emit fugitive emissions of VOC at an oil and natural gas
source, such as valves, connectors, pressure relief devices, open-ended
lines, access doors, flanges, closed-vent systems, covers, thief
hatches or other openings on a controlled storage vessel, compressors,
instruments, and meters. Devices that vent as part of normal
operations, such as natural gas-driven pneumatic controllers or natural
gas-driven pumps, are not fugitive emissions components, insofar as the
natural gas discharged from the device's vent is not considered a
fugitive emission. Emissions originating from other than the vent, such
as the thief hatch on a controlled storage vessel, would be considered
fugitive emissions.
    Glycol dehydration unit process vent emissions means VOC-containing
emissions from the glycol dehydration unit regenerator or still vent
and the vent from the dehydration unit flash tank (if present).
    Malfunction alarm and remote notification system means a system
connected to an electronically controlled automatic ignition device
that sends an alarm through a remote notification system to an owner or
operator's central control center, if an attempt to relight the pilot
flame is unsuccessful.
    Pneumatic pump means a single diaphragm pump powered by pressurized
natural gas.
    Pneumatic pump emissions means the VOC-containing emissions from
pressurized natural gas-driven pneumatic pumps.
    Produced natural gas means natural gas that is separated from
extracted reservoir fluids during oil and natural gas production
operations.
    Regional Administrator means the Regional Administrator of EPA
Region 8 or an authorized representative of the Regional Administrator
of EPA Region

8, except to the extent otherwise specifically specified in a
Delegation of Authority Agreement between the Regional Administrator
and the Ute Indian Tribe.
    Standing and breathing losses means VOC emissions from fixed roof
tanks as a result of evaporative losses during storage.
    Storage tank means a tank or other vessel that contains an
accumulation of crude oil, condensate, intermediate hydrocarbon
liquids, or produced water, and that is constructed primarily of non-
earthen materials (such as wood, concrete, steel, fiberglass, or
plastic), which provide structural support.
    Submerged fill pipe means any fill pipe with a discharge opening
which is entirely submerged when the liquid level is six inches above
the bottom of the tank and the pipe normally used to withdraw liquid
from the tank can no longer withdraw any liquid.
    Supervisory Control and Data Acquisition (SCADA) system generally
refers to industrial control computer systems that monitor and control
industrial infrastructure or source-based processes.
    Unsafe to repair means (in the context of fugitive emissions
monitoring) that operator personnel would be exposed to an imminent or
potential danger as a consequence of the attempt to repair the leak
during normal operation of the source.
    Utility flare means a thermal oxidation system using an open
(without enclosure) flame that is designed and operated in accordance
with the requirements of 40 CFR 60.18(b). An enclosed combustor is not
considered a utility flare. A combustion device is not considered a
utility flare when installed horizontally or vertically within an open
pit and often used in oil and natural gas operations to combust
produced natural gas during initial well completion or temporarily
during emergencies when enclosed combustors or utility flares installed
at a source are not operational or injection of recovered produced
natural gas is unavailable.
    Visible smoke emissions mean air pollution generated by thermal
oxidation in a flare or enclosed combustor and occurring immediately
downstream of the flame present in those units. Visible smoke occurring
within, but not downstream of, the flame, does constitute visible smoke
emissions.
    Working losses means natural gas emissions from fixed roof tanks
resulting from evaporative losses during filling and emptying
operations.

Sec.  49.4172  Emissions inventory.

    (a) Applicability. The emissions inventory requirements of this
section apply to each oil and natural gas source as identified in Sec.
49.4169(b), and that has actual emissions of any pollutant identified
in paragraph (c) of this section greater than or equal to one ton in
any consecutive 12-month period.
    (b) Each oil and natural gas source shall submit an inventory for
every third year, beginning with the 2017 calendar year, for all
emission units at a source.
    (c) The inventory shall include the total emissions for
PM10, PM2.5, oxides of sulfur, oxides of
nitrogen, carbon monoxide and volatile organic compounds for each
emissions unit at the source. Emissions for the emissions unit at the
source shall be calculated using the emissions unit's actual operating
hours, product rates and types of materials processed, stored or
combusted during the calendar year of the reporting period.
    (d) The inventory shall include the type and efficiency of any air
pollution control equipment present at the reporting source.
    (e) The inventory shall be submitted to the EPA Region 8 Office no
later than April 15th of the year following each inventory year, except
that the first inventory covering calendar year 2017 shall be submitted
no later than October 1, 2018.
    (f) The inventory shall be submitted in an electronic format
specific to this source category that is available on the EPA Region 8
Office website at https://www.epa.gov/air-quality-implementation-plans/approved-air-quality-implementation-plans-region-8.

Sec.  49.4173  Compliance with the National Indian Country Oil and
Natural Gas Federal Implementation Plan for New and Modified True Minor
Oil and Natural Gas Sources in the Uinta Basin Ozone Nonattainment
Area.

    (a) Applicability. This section applies to each owner or operator
of a new and modified true minor source in the oil and natural
production and natural gas processing segments of the oil and natural
gas source sector that is located on portions of the U&O Reservation
that are included in the Uinta Basin ozone nonattainment area and that
commences construction on or after [30 DAYS AFTER DATE OF PUBLICATION
OF THE FINAL RULE IN THE FEDERAL REGISTER]. Owners/operators of such
sources shall comply with the requirements of the Federal
Implementation Plan for Managing Air Emissions from True Minor Sources
in Indian Country in the Oil and Natural Gas Production and Natural Gas
Processing Segments of the Oil and Natural Gas Sector at 49.101 through
49.105, as applicable, except for Sec.  49.101(b)(1)(v), and,
applicable requirements of the Federal Minor New Source Review Program
in Indian Country at 40 CFR 49.151 through 49.161.
    (b) Complying with the requirements of Sec.  49.4173(a) does not
relieve the owner/operator from the obligation to comply with the
requirements of Sec. Sec.  49.4169 through 49.4171 and 49.4174 through
49.4185, as applicable.

Sec.  49.4174  VOC emissions control requirements for storage tanks.

    (a) Applicability. The VOC emissions control requirements of this
section apply to each crude oil, condensate, and/or produced water
storage tank located at an oil and natural gas source as identified in
Sec.  49.4169(b) that meets the criteria in one of paragraphs (1)
through (4):
    (1) At an oil and natural gas source that began operations before
[30 DAYS AFTER DATE OF PUBLICATION OF THE FINAL RULE IN THE FEDERAL
REGISTER], the source-wide uncontrolled actual VOC emissions from all
storage tanks, glycol dehydrators, and pneumatic pumps is equal to or
greater than 4 tpy, as determined according to this section;
    (2) At an oil and natural gas source that began operations on or
after [30 DAYS AFTER DATE OF PUBLICATION OF THE FINAL RULE IN THE
FEDERAL REGISTER], upon startup of operation, for a minimum of 12
consecutive calendar months;
    (3) At an oil and natural gas source that began operations before
[30 DAYS AFTER DATE OF PUBLICATION OF THE FINAL RULE IN THE FEDERAL
REGISTER], with one or more storage tanks and no glycol dehydrators or
pneumatic pumps, the source-wide throughput is equal to or greater than
8,000 barrels of crude oil or 2,000 barrels of condensate in any
consecutive 12-month period; or
    (4) Modification to an oil and natural gas source shall require a
re-evaluation of the source-wide VOC emissions from all storage tanks,
glycol dehydrators and pneumatic pumps or the source-wide crude oil or
condensate throughput.
    (b) Exemptions. (1) This section does not apply to crude oil,
condensate, and/or produced water storage tanks located at an oil and
natural gas source that are subject to the emissions control
requirements for storage vessels in 40 CFR part 60, subparts OOOO or
OOOOa, or 40 CFR part 63, subpart HH.
    (2) This section does not apply to an emergency storage tank
located at an oil

and natural gas source, if it meets the following requirements:
    (i) The emergency storage tank is not used as an active storage
tank;
    (ii) The owner or operator empties the emergency storage tank no
later than 15 days after receiving fluids; and
    (iii) The emergency storage tank is equipped with a liquid level
gauge or equivalent device.
    (c) VOC emission control requirements. For each storage tank, you
must comply with the VOC emissions control requirements of paragraphs
(1) or (2) of this section.
    (1) You must reduce VOC emissions from each storage tank by at
least 95.0 percent on a continuous basis according to paragraphs
(c)(1)(i) or (ii) of this section. You must route all flashing,
working, standing and breathing losses from the crude oil, condensate,
and/or produced water storage tanks through a closed-vent system that
meets the conditions specified in Sec.  49.4177(d) to:
    (i) An operating system designed to recover 100 percent of the
emissions and recycle them for use in a process unit or incorporate
them into a product; or
    (ii) An enclosed combustor or utility flare designed to reduce the
mass content of VOC in the natural gas emissions vented to the device
by at least 95.0 percent and operated as specified in Sec. Sec.
49.4177(d) and 49.4178;
    (2) You must maintain the source-wide uncontrolled actual VOC
emissions from all storage tanks, glycol dehydrators, and pneumatic
pumps at an oil and natural gas source at less than 4 tpy. Before using
the uncontrolled actual VOC emission rate for compliance purposes, you
must demonstrate that the uncontrolled actual VOC emissions have
remained at less than 4 tpy, as determined monthly for 12 consecutive
months. After such demonstration, you must determine the uncontrolled
actual VOC emission rate each month. The uncontrolled actual VOC
emissions must be calculated using a generally accepted model or
calculation methodology. Monthly calculations must be based on the
average throughput of the source for the month. Monthly calculations
must be separated by at least 14 days. You must comply with paragraph
(c)(1) of this section within 30 days of the monthly emissions
determination required in this section if the determination indicates
that VOC emissions from all storage tanks, glycol dehydrators, and
pneumatic pumps at your oil and natural gas source increased to 4 tpy
or greater.
    (3) Except as provided in paragraph (c)(4) of this section, if you
use a control device to reduce emissions from your storage tanks, you
must equip each storage tank with a cover that meets the requirements
of Sec.  49.4177(c).
    (4) If you use a floating roof to reduce emissions, you must meet
the requirements of Sec.  60.112b(a)(1) or (2) and the relevant
monitoring, inspection, recordkeeping, and reporting requirements in 40
CFR part 60, subpart Kb.
    (5) After a minimum of 12 consecutive months of operation at a
source that begins operation on or after [30 DAYS AFTER DATE OF
PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER], controls may be
removed under one of the following conditions:
    (i) The source-wide uncontrolled actual VOC emissions from all
storage tanks, glycol dehydrators, and pneumatic pumps has been
maintained at a rate less than 4 tpy, as determined according to this
section; or
    (ii) At a source with one or more storage tanks and no glycol
dehydrators or pneumatic pumps, the source-wide throughput is less than
8,000 barrels of crude oil or 2,000 barrels of condensate.

Sec.  49.4175  VOC emissions control requirements for dehydrators.

    (a) Applicability. The VOC emissions control requirements of this
section apply to each glycol dehydration unit located at an oil and
natural gas source as identified in Sec.  49.4169(b) where the source-
wide uncontrolled actual VOC emissions from all storage tanks, glycol
dehydrators, and pneumatic pumps is equal to or greater than 4 tpy, as
determined according to Sec.  49.4174. Applicability for glycol
dehydrators that began operation before [30 DAYS AFTER DATE OF
PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] shall be
determined using uncontrolled actual emissions. Applicability for
glycol dehydrators that began operation on or after [30 DAYS AFTER DATE
OF PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] shall be
determined using potential to emit.
    (b) Exemptions. This section does not apply to glycol dehydration
units subject to with the emissions control requirements for glycol
dehydration unit process vents in 40 CFR, part 63, subpart HH.
    (c) VOC emissions control requirements. For each glycol dehydration
unit, you must comply with the VOC emissions control requirements of
paragraphs (1) or (2) of this paragraph.
    (1) You must reduce VOC emissions from each glycol dehydration unit
process vent by at least 95.0 percent on a continuous basis according
to paragraphs (c)(1)(i) and (ii) of this section. You must route all
glycol dehydration unit process vent emissions through a closed-vent
system that meets the conditions specified in Sec.  49.4177(d) to:
    (i) An operating system designed to recover 100 percent of the
emissions and recycle them for use in a process unit or incorporate
them into a product; or
    (ii) An enclosed combustor or utility flare designed to reduce the
mass content of VOC in the emissions vented to the device by at least
95.0 percent and operated as specified in Sec. Sec.  49.4177(d) and
49.4178; or
    (2) You must maintain the source-wide uncontrolled actual VOC
emissions from all storage tanks, glycol dehydrators, and pneumatic
pumps at an oil and natural gas source at less than 4 tpy for 12
consecutive months in accordance with the procedures specified in Sec.
49.4174(c)(2).

Sec.  49.4176  VOC emissions control requirements for pneumatic pumps.

    (a) Applicability. The requirements of this section apply to each
pneumatic pump located at an oil and natural gas source as identified
in Sec.  49.4169(b) where the potential for source-wide uncontrolled
VOC emissions from all storage tanks, glycol dehydrators, and pneumatic
pumps is equal to or greater than 4 tpy, as determined according to
Sec.  49.4174. You must reevaluate the source-wide VOC emissions from
all storage tanks, glycol dehydrators and pneumatic pumps for each
modification to an existing source.
    (b) Exemptions. This section does not apply to pneumatic pumps
subject to the emissions control requirements for pneumatic pumps in 40
CFR part 60, subpart OOOOa.
    (c) VOC Emission Control Requirements. For each pneumatic pump, you
must comply with the VOC emissions control requirements of paragraph
(1) or (2) of this section.
    (1) You must reduce VOC emissions from each pneumatic pump by at
least 95.0 percent on a continuous basis according to paragraph
(c)(1)(i) or (ii) of this section. You must route all pneumatic pump
emissions through a closed-vent system that meets the conditions
specified in Sec.  49.4177(d) to:
    (i) An operating system designed to recover 100 percent of the
emissions and recycle them for use in a process unit or incorporate
them into a product; or
    (ii) An enclosed combustor or utility flare designed to reduce the
mass

content of VOC in the emissions vented to the device by at least 95.0
percent and operated as specified in Sec. Sec.  49.4177(d) and 49.4178;
or
    (2) You must maintain the source-wide uncontrolled actual VOC
emissions from all storage tanks, glycol dehydrators, and pneumatic
pumps at an oil and natural gas source at less than 4 tpy for any 12
consecutive months in accordance with the procedures specified in Sec.
49.4174(c)(2).

Sec.  49.4177  VOC emissions control requirements for covers and
closed-vent systems.

    (a) Applicability. The VOC emissions control requirements in this
section apply to each cover on a crude oil, condensate or produced
water storage tank subject to Sec.  49.4174 and each closed-vent system
used to convey VOC emissions from storage tanks, glycol dehydration
units and pneumatic pumps (to a vapor recovery system or control
device) that are subject to Sec. Sec.  49.4174 through 49.4176.
    (b) Exemptions. This section does not apply to covers and closed-
vent systems subject to the requirements for covers and closed-vent
systems in 40 CFR part 60, subparts OOOO or OOOOa, or 40 CFR part 63,
subpart HH.
    (c) Covers. Each owner or operator must equip all openings on each
crude oil, condensate, and/or produced water storage tank with a cover
to ensure that all flashing, working, standing and breathing emissions
are routed through a closed-vent system to a vapor recovery system, an
enclosed combustor, or a utility flare.
    (1) Each cover and all openings on the cover (e.g., access hatches,
sampling ports, pressure relief valves (PRV), and gauge wells) must
form a continuous impermeable barrier over the entire surface area of
the crude oil, condensate, and/or produced water in the storage tank.
    (2) 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
unit on which the cover is installed except when it is necessary to use
an opening as follows:
    (i) To add fluids to, or remove fluids 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 fluids in the unit; or
    (iii) To inspect, maintain, repair, or replace equipment located
inside the unit.
    (3) Each thief hatch cover must be weighted and properly seated to
ensure that flashing, working, standing and breathing emissions are
routed through the closed-vent system to the vapor recovery system, the
enclosed combustor, or the utility flare under normal operating
conditions.
    (4) Each PRV must be set to release at a pressure that will ensure
that flashing, working, standing and breathing emissions are routed
through the closed-vent system to the vapor recovery system, the
enclosed combustor, or the utility flare under normal operating
conditions.
    (d) Closed-vent systems. Each owner or operator must meet the
following requirements for closed-vent systems:
    (1) Each closed-vent system must route all captured storage tank
flashing, working, standing and breathing losses, glycol dehydration
unit process vent emissions, and pneumatic pump emissions from the oil
and natural gas source to a gathering pipeline system for sale, use in
a process unit, incorporation into a product, or other beneficial
purpose, or to a VOC emission control device, as specified in
Sec. Sec.  49.4174 through 49.4176.
    (2) All vent lines, connections, fittings, valves, relief valves,
or any other appurtenance employed to contain and collect captured
storage tank flashing, working, standing and breathing losses, glycol
dehydration unit process vent emissions, and pneumatic pump emissions
to transport such emissions to a gathering pipeline system for sale,
use in a process unit, incorporation into a product, or other
beneficial purpose, or to a VOC emission control device, as specified
in Sec. Sec.  49.4174 through 49.4176, must be maintained and operated
properly at all times.
    (3) Each closed-vent system must be designed to operate with no
detectable emissions, as demonstrated by the fugitive emissions
component monitoring requirements in Sec.  49.4179(c).
    (4) If any closed-vent system contains one or more bypass devices
that could be used to divert all or a portion of the captured storage
tank flashing, working, standing and breathing losses, glycol
dehydration unit process vent emissions, and pneumatic pump emissions,
from entering a gathering pipeline system for sale, use in a process
unit, incorporation into a product, or other beneficial purpose, or
from being transferred to the VOC emissions control device, the owner
or operator must meet one of the requirements in paragraphs (i) or (ii)
for each bypass device. 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:
    (i) At the inlet to such a bypass device the owner or operator must
properly install, calibrate, maintain, and operate a flow indicator
that is capable of taking continuous readings and sounding an alarm
when the bypass device is open such that emissions are being, or could
be, diverted away from a gathering pipeline system for sale, use in a
process unit, incorporation into a product, or other beneficial
purpose, or the VOC emission control device and into the atmosphere; or
    (ii) The owner or operator must 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.

Sec.  49.4178  VOC emissions control devices.

    (a) Applicability. The requirements in this section apply to all
utility flares and enclosed combustors used to control VOC emissions at
an oil and natural gas source as identified in Sec.  49.4169(b) in
order to meet the requirements specified in Sec. Sec.  49.4174 through
49.4177, as applicable.
    (b) Exemptions. This section does not apply to VOC emission control
devices subject to the requirements for control devices used to comply
with the emissions standards in 40 CFR part 60, subparts OOOO or OOOOa;
or 40 CFR part 63, subpart HH.
    (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) The owner or operator must ensure that each enclosed combustor
or utility flare is designed to have sufficient capacity to reduce the
mass content of VOC in the captured emissions routed to it by at least
95.0 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 captured emissions routed to it
by continuously meeting at least 95.0 percent VOC control efficiency;
    (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 meet the VOC control
efficiency requirements of Sec. Sec.  49.4174 through 49.4177 using the
EPA-approved performance test procedures specified in 40 CFR 60.5413 by
the due date of the first annual report as specified in Sec.
49.4185(b); and
    (ii) Demonstrated by the owner or operator to meet the VOC control
efficiency requirements of Sec. Sec.  49.4174 through 49.4177 using the
EPA-approved performance test procedures specified in 40 CFR 60.5413 by
the due date of the first annual report as specified in Sec.
49.4183(b); and
    (6) The owner or operator must ensure that each enclosed combustor
and utility flare is:
    (i) Operated properly at all times that captured 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 and operated with a flash-back flame arrestor;
    (iv) Equipped and operated with one of the following:
    (A) A continuous burning pilot; or
    (B) An operational electronically controlled automatic ignition
device;
    (v) Equipped with a monitoring system for continuous measuring and
recording of the parameters that indicate proper operation of each
continuous burning pilot flame or electronically controlled automatic
ignition device (such as a chart recorder, data logger or similar
device), or connected to a 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.

Sec.  49.4179  Fugitive emissions VOC emissions control requirements.

    (a) Applicability. The requirements of this section apply to all
owners or operators of the collection of fugitive emissions components,
as defined in Sec.  49.4171, at an oil and natural gas source, as
identified in Sec.  49.4169(b), that is required to control VOC
emissions according to Sec. Sec.  49.4174 through 49.4178.
    (b) Exemptions. This section does not apply to owners or operators
of the collection of fugitive emission components, as defined in 40 CFR
60.5430a, at an oil and natural gas source subject to the fugitive
emissions monitoring requirements in 40 CFR part 60, subpart OOOOa.
    (c) Monitoring requirements. (1) Each owner or operator must
develop and implement a fugitive emissions monitoring plan to reduce
emissions from fugitive emissions components at all of their oil and
natural gas sources on Indian country lands within the U&O Reservation.
This Reservation-wide monitoring plan must include the following
elements:
    (i) A requirement to perform an initial monitoring of the
collection of fugitive emissions components at each oil and natural gas
source by [DATE 18 MONTHS AFTER DATE OF PUBLICATION OF THE FINAL RULE
IN THE FEDERAL REGISTER];
    (ii) A requirement to perform subsequent monitoring of the
collection of fugitive emissions components at each oil and natural gas
source once every 6 months after the initial monitoring survey, with
consecutive monitoring surveys conducted at least five months apart.
    (iii) A description of the technique used to identify leaking
fugitive emission components, which must be limited to:
    (A) Onsite EPA Reference Method 21, 40 CFR part 60, appendix A,
where an analyzer reading of 500 parts per million volume (ppmv) VOC or
greater is considered a leak in need of repair;
    (B) Onsite optical gas imaging instruments, as defined in 40 CFR
60.18(g)(4), where any visible emissions are considered a leak in need
of repair, unless the owner or operator evaluates the leak with an
analyzer meeting EPA Reference Method 21 at 40 CFR part 60, appendix A
and the concentration is less than 500 ppmv. The optical gas imaging
instrument must be capable of meeting the optical gas imaging equipment
requirements specified in 40 CFR part 60, subpart OOOOa; or
    (C) Another method approved by the Administrator other than EPA
Reference Method 21 or optical gas imaging instruments to demonstrate
compliance with the fugitive emissions monitoring requirements.
    (iv) The manufacturer and model number of any fugitive emissions
monitoring device to be used;
    (v) Procedures and timeframes for identifying and repairing
components from which leaks are detected, including:
    (A) A requirement to repair any leaks identified from components
that are safe to repair and do not require source shutdown as soon as
practicable, but no later than 30 calendar days after discovering the
leak;
    (B) Timeframes for repairing leaking components that are unsafe to
repair or require source shutdown, to be no later than the next
required monitoring event; and
    (C) Procedures for verifying leaking component repairs, no more
than 30 calendar days after repairing the leak;
    (vi) Training and experience needed before performing surveys;
    (vii) Procedures for calibration and maintenance of any fugitive
emissions monitoring device to be used; and
    (viii) Standard monitoring protocols for each type of typical oil
and natural gas source (e.g., well site, tank battery, compressor
station), including a general list of component types that will be
inspected and what supporting data will be recorded (e.g., wind speed,
detection method device-specific operational parameters, date, time,
and duration of inspection).
    (2) The owner or operator is exempt from inspecting a valve,
flange, or other connection, pump or compressor, pressure relief
device, process drain, open-ended valve, pump or compressor seal system
degassing vent, accumulator vessel vent, agitator seal, or access door
seal under any of the following circumstances:
    (i) The contacting process stream only contains glycol, amine,
methanol, or produced water;
    (ii) If using Method 21, the monitoring could not occur without
elevating the monitoring personnel to an immediate danger as a
consequence of completing monitoring;
    (iii) Monitoring could not occur without exposing monitoring
personnel to an immediate danger as a consequence of completing
monitoring; or
    (iv) The item to be inspected is buried, insulated in a manner that
prevents access to the components by a monitor probe or optical gas
imaging device, or obstructed by equipment or piping that prevents
access to the components by a monitor probe or optical gas imaging
device.

Sec.  49.4180  Tank truck loading VOC emissions control requirements.

    (a) Applicability. The requirements in this section apply to each
owner or operator who loads or permits the loading of any intermediate
hydrocarbon liquid or produced water at an oil and natural gas source
as identified in Sec.  49.4169(b).
    (b) Tank truck loading requirements. Tank trucks used for
transporting intermediate hydrocarbon liquid or produced water must be
loaded using bottom filling or a submerged fill pipe, as defined in
Sec.  49.4171(b).

Sec.  49.4181  VOC emissions control requirements for pneumatic
controllers.

    (a) Applicability. The VOC emissions control requirements in this
section apply to each owner or operator of any existing pneumatic
controller located at an oil and natural gas source as identified in
Sec.  49.4169(b).
    (b) Exemptions. This section does not apply to pneumatic
controllers subject to and controlled in accordance with the
requirements for pneumatic controllers in 40 CFR part 60, subparts OOOO
or OOOOa.
    (c) Retrofit requirements. All existing pneumatic controllers must
meet the standards established for pneumatic controllers that are
constructed, modified, or reconstructed on or after October 15, 2013,
as specified in 40 CFR part 60, subpart OOOO Standards of Performance
for Crude Oil and Natural Gas Production, Transmission and
Distribution.
    (d) Documentation requirements. The owner or operator of any
existing pneumatic controllers must meet the tagging requirements in 40
CFR 60.5390(b)(2) and (c)(2) and 40 CFR 60.5390a(b)(2) and (c)(2),
except that the month and year of installation, reconstruction or
modification is not required.

Sec.  49.4182  Other combustion devices.

    (a) Applicability. The VOC emission control requirements in this
section apply to each owner or operator of any existing enclosed
combustor, utility flare, or other flare located at an oil and natural
gas source as identified in Sec.  49.4169(b) that is used to control
VOC emissions, but is not required under Sec. Sec.  49.4174 through
49.4176, and 49.4178 of this rule.
    (b) Retrofit requirements. All existing enclosed combustors,
utility flares, or other open flares must be equipped with an
operational electronically controlled automatic ignition device.

Sec.  49.4183  Monitoring requirements.

    (a) Applicability. The monitoring requirements in paragraphs (c)
through (e) of this section apply, as appropriate, to each oil and
natural gas source as identified in Sec.  49.4169(b) with equipment or
activities that are subject to Sec. Sec.  49.4174 through 49.4178.
    (b) Exemptions. Paragraphs (c) through (e) do not apply to any
crude oil, condensate, or produced water storage tanks, glycol
dehydration units, pneumatic pumps, covers, closed-vent systems or VOC
emission control devices subject to and monitored in accordance with
the monitoring requirements for such equipment and activities in 40 CFR
part 60, subparts OOOO or OOOOa, or 40 CFR part 63, subpart HH.
    (c) Each owner or operator must inspect at least once every
calendar month each closed-vent system, including storage tank
openings, thief hatches, and bypass devices, for defects that can
result in air emissions according to the procedures in 40 CFR
60.5416(c).
    Any defects identified must be corrected or repaired within 15 days
of identification.
    (d) Each owner or operator must perform auditory, visual, and
olfactory (AVO) inspections at least once every calendar month of each
VOC emissions control device, tank thief hatch, cover, seal, pressure
relief valve, and closed-vent system to ensure proper condition and
functioning of the equipment. The monthly inspections must be performed
while the crude oil, condensate, and produced water storage tanks are
being filled. If any of the components are not in good working
condition, they must be repaired within 15 days of identification of
the deficient condition.
    (e) Each owner or operator must monitor the operation of each
enclosed combustor and utility flare to confirm proper operation and
demonstrate compliance with the requirements of Sec.  49.4178(c)(6)(iv)
and (v), as follows:
    (1) Check the system for proper operation whenever an operator is
on site, at least once per calendar month; and
    (2) Respond to any indication of pilot flame failure and ensure
that the pilot flame is relit as soon as practically and safely
possible after discovery.;
    (3) Demonstrate compliance with the requirements of Sec.
49.4178(c)(6)(vii), that each enclosed combustor is operated with no
visible smoke emissions, by complying with the requirements in 40 CFR
60.5412(d)(i) through (iii).
    (f) Where sufficient to meet the monitoring requirements in this
section, the owner or operator may use a SCADA system to monitor and
record the required data in paragraphs (c) through (d).

Sec.  49.4184  Recordkeeping requirements.

    (a) Each owner or operator of an oil and natural gas source as
identified in Sec.  49.4169(b) must maintain the following records, as
applicable:
    (1) For each oil and natural gas source as identified in Sec.
49.4169(b):
    (i) As applicable, the monthly calculations, as specified in Sec.
49.4174(c)(2), demonstrating that the uncontrolled actual VOC emissions
from all storage tanks, glycol dehydrators, and pneumatic pumps at an
oil and natural gas source, as identified in Sec.  49.4169(b), has been
maintained at less than 4 tpy;
    (ii) As applicable, records of monthly and rolling 12-month crude
oil or condensate throughput;
    (iii) For each enclosed combustor or utility flare at an oil and
natural gas source required under Sec. Sec.  49.4174 through 49.4178:
    (A) Manufacturer-written, site-specific designs, operating
instructions, operating procedures and maintenance schedules, including
those of any operation monitoring systems;
    (B) Date of installation;
    (C) Records of all required monitoring of operations in Sec.
49.4183;
    (D) Records of any instances in which the pilot flame is not
present or the monitoring equipment is not functioning in the enclosed
combustor or utility flare, the date and times of the occurrence, the
corrective actions taken, and any preventative measures adopted to
prevent recurrence of the occurrence; and
    (E) Records of any time periods in which visible smoke emissions
are observed emanating from the enclosed combustor or utility flare.
    (iv) For each closed-vent system:
    (A) The date of installation; and
    (B) 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
    (v) Documentation of all storage tank and closed-vent system
inspections required in Sec.  49.4183(d) and (e) All inspection records
must include the following information:
    (A) The date of the inspection;
    (B) The findings of the inspection;
    (C) Any adjustments or repairs made as a result of the inspection,
and the date of the adjustment or repair; and
    (D) The inspector's name and signature;
    (vi) The Uinta Basin-wide fugitive emissions monitoring plan for
the U&O Reservation; and
    (vii) Documentation of each fugitive emissions inspection at all
oil and natural gas sources. All inspection records must include the
following information:
    (A) The date of the inspection;
    (B) The identification of any component that was determined to be
leaking;
    (C) The identification of any component not exempt under Sec.
49.4179(b)(2) that is not inspected and the reason it was not
inspected;
    (D) The date of the first attempt to repair the leaking component;

    (E) The identification of any component with a delayed repair and
the reason for the delayed repair:
    (1) For unavailable parts:
    (i) The date of ordering a replacement component; and
    (ii) The date the replacement component was received; and
    (2) For a shutdown:
    (i) The reason the repair is technically infeasible;
    (ii) The date of the shutdown;
    (iii) The date of subsequent startup after a shutdown; and
    (iv) Emission estimates of the shutdown and the repair if the delay
is longer than 6 months;
    (F) The date and description of any corrective action taken,
including the date the component was verified to no longer be leaking;
    (G) The identification of each component exempt under Sec.
49.4179(b)(2), including the type of component and a description of the
qualifying exemption; and
    (H) The inspector's name and signature.
    (2) For each oil and natural gas source as identified in Sec.
49.4169(b):
    (i) For each electronically controlled automatic ignition system
required under Sec.  49.4182, records demonstrating the date of
installation and manufacturer specifications; and
    (ii) For each retrofitted pneumatic controller, the records
required in 40 CFR 60.5420(c)(4)(i).
    (b) Each owner or operator must keep all records required by this
section onsite at the source or at the location that has day-to-day
operational control over the source 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 years from the date the record
was created.

Sec.  49.4185  Notification and reporting requirements.

    (a) Each owner or operator must submit any documents required under
this rule to: U.S. EPA Region 8, Enforcement and Compliance Assurance
Division, Air Toxics and Enforcement Branch, 8ENF-AT, 1595 Wynkoop St.,
Denver, CO 80202, or 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 (3) of this
section. The annual report must cover the period for the previous
calendar year. The initial annual report is due within fifteen months
of [DATE 30 DAYS AFTER DATE OF PUBLICATION OF THE FINAL RULE IN THE
FEDERAL REGISTER]. Subsequent annual reports are due on the same date
each year as the date the initial annual report was submitted. If you
own or operate more than one oil and natural gas source, you may submit
one report for multiple oil and natural gas sources provided the report
contains all of the information required as specified in paragraphs
(b)(1) through (3) of this section. Annual reports may coincide with
title V reports as long as all the required elements of the annual
report are included. An alternative schedule on which the annual must
be submitted will be allowed as long as the schedule does not extend
the reporting period. The annual report must include:
    (1) The owner or operator name, and the name and location (decimal
degree latitude and longitude location indicating the datum used in
parentheses) of each oil and natural gas source being included in the
annual report.
    (2) The beginning and ending dates of the reporting period.
    (3) For each oil and natural gas source a summary of all required
records specified in Sec.  49.4183 as they relate to the source's
compliance with the requirements of Sec. Sec.  49.4174 through 49.4183.

[FR Doc. 2019-27431 Filed 1-17-20; 8:45 am]
BILLING CODE 6560-50-P