Rule2022-24677
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
Primary source
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Published
December 8, 2022
Effective
February 6, 2023
Issuing agencies
Environmental Protection Agency
Abstract
The Environmental Protection Agency (EPA) is promulgating a Federal Implementation Plan (FIP) under the Clean Air Act (CAA) and the EPA's implementing regulations that consists of emissions control requirements for existing, new, and modified oil and natural gas sources on Indian country lands within the Uintah and Ouray Indian Reservation (also referred to as the U&O Reservation) to address air quality in and around the Uinta Basin Ozone Nonattainment Area in northeast Utah. This U&O FIP establishes volatile organic compound (VOC) emissions control requirements for oil and natural gas production and processing on Indian country lands within the U&O Reservation. These requirements are consistent with those in place in areas within the Basin where the EPA has approved Utah to implement the CAA, and will help ensure that new development of oil and natural gas sources in the Basin will not interfere with attainment of the ozone National Ambient Air Quality Standard (NAAQS). VOC emissions control requirements for existing oil and natural gas sources have already been established in areas within the Basin where the EPA has approved Utah to implement the CAA, but did not exist for most sources on Indian country lands within the U&O Reservation. Additionally, this U&O FIP helps demonstrate that new development on Indian country lands within the U&O Reservation will not necessarily cause or contribute to an ozone NAAQS violation.
Full Text
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[Federal Register Volume 87, Number 235 (Thursday, December 8, 2022)]
[Rules and Regulations]
[Pages 75334-75386]
From the Federal Register Online via the Government Publishing Office [<a href="http://www.gpo.gov">www.gpo.gov</a>]
[FR Doc No: 2022-24677]
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Vol. 87
Thursday,
No. 235
December 8, 2022
Part II
Environmental Protection Agency
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40 CFR Part 49
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; Final Rule
Federal Register / Vol. 87, No. 235 / Thursday, December 8, 2022 /
Rules and Regulations
[[Page 75334]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 49
[EPA-R08-OAR-2015-0709; FRL-5872.1-01-R8]
RIN 2008-AA03
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
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
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SUMMARY: The Environmental Protection Agency (EPA) is promulgating a
Federal Implementation Plan (FIP) under the Clean Air Act (CAA) and the
EPA's implementing regulations that consists of emissions control
requirements for existing, new, and modified oil and natural gas
sources on Indian country lands within the Uintah and Ouray Indian
Reservation (also referred to as the U&O Reservation) to address air
quality in and around the Uinta Basin Ozone Nonattainment Area in
northeast Utah. This U&O FIP establishes volatile organic compound
(VOC) emissions control requirements for oil and natural gas production
and processing on Indian country lands within the U&O Reservation.
These requirements are consistent with those in place in areas within
the Basin where the EPA has approved Utah to implement the CAA, and
will help ensure that new development of oil and natural gas sources in
the Basin will not interfere with attainment of the ozone National
Ambient Air Quality Standard (NAAQS). VOC emissions control
requirements for existing oil and natural gas sources have already been
established in areas within the Basin where the EPA has approved Utah
to implement the CAA, but did not exist for most sources on Indian
country lands within the U&O Reservation. Additionally, this U&O FIP
helps demonstrate that new development on Indian country lands within
the U&O Reservation will not necessarily cause or contribute to an
ozone NAAQS violation.
DATES: This final rule is effective on February 6, 2023.
ADDRESSES: The EPA has established a docket for this action under
Docket ID No. EPA-R08-OAR-2015-0709. All documents in the docket are
listed on the <a href="http://www.regulations.gov">www.regulations.gov</a> website. In some instances, we
reference documents from the dockets for other rulemakings. For this
final rule, we have included by reference Docket ID No. EPA-HQ-OAR-
2010-0505, Docket ID No. EPA-R08-OAR-2012-0479, Docket ID No. EPA-HQ-
OAR-2003-0076, and Docket ID No. EPA-HQ-OAR-2014-0606 into Docket ID
No. EPA-R08-OAR-2015-0709. Although listed in the index, some
information is not publicly available, e.g., CBI or other information
for which disclosure is restricted by statute. Certain other material,
such as copyrighted material, will be publicly available only in hard
copy. Publicly available docket materials are available through <a href="http://www.regulations.gov">http://www.regulations.gov</a>, or please contact the person identified in the FOR
FURTHER INFORMATION CONTACT section for additional availability
information.
FOR FURTHER INFORMATION CONTACT: Ms. Claudia Smith, U.S. EPA, Region 8,
Air and Radiation Division, Mail Code 8ARD-IO, 1595 Wynkoop Street,
Denver, Colorado 80202-1129, telephone number: (303) 312-6520, email
address: <a href="/cdn-cgi/l/email-protection#73001e1a071b5d101f1206171a12331603125d141c05"><span class="__cf_email__" data-cfemail="abd8c6c2dfc385c8c7cadecfc2caebcedbca85ccc4dd">[email protected]</span></a>.
SUPPLEMENTARY INFORMATION:
Definitions
Act or CAA: Clean Air Act, unless the context indicates
otherwise.
AVO: Audio, Visual and Olfactory.
BTU: British Thermal Unit.
CBI: Confidential Business Information.
CEDRI: Compliance Emissions Data Reporting Interface.
CO: carbon monoxide.
EPA, we, us or our: The United States Environmental Protection
Agency.
FBIR: Fort Berthold Indian Reservation.
FIP: Federal Implementation Plan.
GOR: gas-to-oil ratio.
HAP: hazardous air pollutants.
NAAQS: National Ambient Air Quality Standards.
NAICS: North American Industry Classification System.
NESHAP: National Emission Standards for Hazardous Air
Pollutants.
NOx: nitrogen oxides.
NO<INF>2</INF>: nitrogen dioxide.
NSPS: New Source Performance Standards.
NSR: New Source Review.
PM: particulate matter.
PSD: Prevention of Significant Deterioration.
PTE: potential to emit.
RIA: Regulatory Impact Analysis.
SCADA: Supervisory Control and Data Acquisition.
SIP: State Implementation Plan.
SO<INF>2</INF>: sulfur dioxide.
TAR: Tribal Authority Rule.
TAS: treatment in a similar manner as a state.
TIP: Tribal Implementation Plan.
tpy: ton(s) per year
UDEQ: Utah Department of Environmental Quality.
U&O Reservation or the Reservation: The Uintah & Ouray Indian
Reservation.
VOC: volatile organic compound(s).
VRU: vapor recovery unit.
Organization of this document. The information presented in this
preamble is organized as follows:
I. Executive Summary
A. Purpose of, and Agency Authority for, the Regulatory Action
B. Summary of the Major Provisions of This Final Rule
C. Costs and Benefits
II. General Information
A. Does this action apply to me?
B. Where can I get a copy of this document and related
information?
C. Judicial Review
III. Background
A. Uintah and Ouray Indian Reservation
B. Tribal Authority Rule
C. Federal Indian Country Minor NSR Rule
D. Air Quality and Attainment Status
E. Emissions Information
F. What is a FIP?
G. Oil and Natural Gas Industry in Uinta Basin
IV. Summary of the Final U&O FIP
A. Overview
B. Introduction
C. Provisions for Delegation of Administration to the Ute Indian
Tribe
D. General Provisions
E. Emissions Inventory Requirements
F. VOC Emissions Control Requirements
G. Monitoring and Testing Requirements
H. Recordkeeping Requirements
I. Notification and Reporting Requirements
V. Significant Changes Since Proposal
A. Final Rule Effective Date and Compliance Deadline
B. Triennial Emissions Inventory
C. Streamlined Construction Authorization
D. Applicability
E. Monitoring and Testing
F. Recordkeeping and Reporting
VI. Summary of Significant Comments and Responses
A. Major Comments Concerning Effective Date and Compliance
Deadline
B. Major Comments Concerning Regulatory Authority for Minor
Source Streamlined Construction Authorization
C. Major Comments Concerning Rule Applicability
D. Major Comments Concerning Monitoring and Testing Requirements
E. Major Comments Concerning Recordkeeping and Reporting
F. Major Comments Concerning Cost-Benefit Analysis
G. Other Comments of Significant Interest
VII. Impacts of This Final FIP
A. Air Emissions Impacts
B. Energy Impacts
C. Compliance Costs
D. Economic and Employment Impacts
E. Benefits
VIII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
B. Paperwork Reduction Act (PRA)
C. Regulatory Flexibility Act (RFA)
D. Unfunded Mandates Reform Act (UMRA)
[[Page 75335]]
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
G. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act (NTTAA)
J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
K. Congressional Review Act (CRA)
I. Executive Summary
A. Purpose of, and Agency Authority for, the Regulatory Action
We are finalizing this action using our authority under sections
301(a) and 301(d)(4) of the CAA and 40 CFR 49.11 to promulgate FIP
provisions that are necessary and appropriate to protect air quality on
the Indian country lands within the U&O Reservation and in nearby
communities. The purpose of this U&O FIP is threefold.
First, and primarily, this U&O FIP will improve air quality on the
U&O Reservation by addressing emissions from oil and natural gas
production and natural gas processing activities on Indian country
lands that contribute to the winter ozone problem in the physiographic
region known as the Uinta Basin,\1\ within which the U&O Reservation is
located, and where ambient ozone levels have exceeded both the 2008 and
the 2015 ozone NAAQS.\2\ In 2018, the EPA designated portions of the
Uinta Basin, including large portions of the Indian country lands
within the U&O Reservation, as a Marginal nonattainment area for the
2015 ozone NAAQS.\3\
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\1\ For this rulemaking, the EPA defines the geographic scope of
the Uinta Basin to be consistent with the Uinta Basin 2014 Air
Agencies Oil and Gas Emissions Inventory (herein after referred to
as the 2014 Uinta Basin Emissions Inventory), which encompasses
Duchesne and Uintah counties. The 2014 Uinta Basin Emissions
Inventory is available at: <a href="https://deq.utah.gov/air-quality/2014-air-agencies-oil-and-gas-emissions-inventory-uinta-basin">https://deq.utah.gov/air-quality/2014-air-agencies-oil-and-gas-emissions-inventory-uinta-basin</a>, accessed
Mar. 11, 2022.
\2\ The 2015 ozone NAAQS is 70 parts per billion (ppb) (40 CFR
50.19). The 2008 ozone NAAQS is 75 ppb. Historical ozone NAAQS
information is available at: <a href="https://www.epa.gov/ozone-pollution/table-historical-ozone-national-ambient-air-quality-standards-naaqs">https://www.epa.gov/ozone-pollution/table-historical-ozone-national-ambient-air-quality-standards-naaqs</a>,
accessed Mar. 11, 2022.
\3\ On April 30, 2018, the EPA designated all of the Uinta Basin
below a contiguous external perimeter of 6,250 ft. in elevation as a
Marginal nonattainment area under the 2015 ozone NAAQS (83 FR
25776). This includes areas of the Basin where the EPA has approved
the UDEQ to implement the CAA and Indian country lands within the
U&O Reservation (where the EPA is promulgating this FIP). For more
information, see <a href="https://www.epa.gov/ozone-designations/additional-designations-2015-ozone-standards">https://www.epa.gov/ozone-designations/additional-designations-2015-ozone-standards</a>, accessed Mar. 11, 2022.
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Air quality ozone monitoring data from the Uinta Basin in the years
2018, 2019 and 2020 indicates that the three-year average of the fourth
maximum ambient air concentration measurements is 76 ppb, which
violates the 2015 ozone NAAQS of 70 ppb. On April 13, 2022, the EPA
proposed to grant a 1-year attainment date extension for the Uinta
Basin Ozone Nonattainment area.\4\ The proposal explains that
preliminary 2021 ozone monitoring data indicate that the area may not
attain the 2015 ozone NAAQS by the proposed extended attainment date of
August 3, 2022, but that the area could meet the air quality criteria
for a second 1-year extension. The Uinta Basin area's preliminary 2019-
2021 design value was 78 ppb and the preliminary 2021 fourth highest
daily maximum 8-hour concentration value was 72 ppb. To qualify for a
second 1-year extension, an area's fourth highest daily maximum 8-hour
value, averaged over both the original attainment year and the first
extension year, must be 70 ppb or less. If the preliminary 2021 ozone
data are certified, then the fourth highest daily maximum 8-hour value,
averaged over 2020 and 2021, would be 69 ppb.\5\
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\4\ See 87 FR 21842 (Apr. 13, 2022), available at <a href="https://www.govinfo.gov/content/pkg/FR-2022-04-13/pdf/2022-07513.pdf">https://www.govinfo.gov/content/pkg/FR-2022-04-13/pdf/2022-07513.pdf</a>,
accessed Apr. 29, 2022.
\5\ Additional details on the proposed extension of the
attainment date are discussed in Section III.D. of this preamble.
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The winter-time ozone formation in the Uinta Basin is caused by
emissions of VOC and NO<INF>X</INF> reacting in the presence of
sunlight and widespread snow cover during temperature inversion
conditions to form ground-level ozone at levels that exceed the ozone
NAAQS and are therefore detrimental to public health. The main sources
in the Basin responsible for VOC and NO<INF>X</INF> emissions are
existing oil and natural gas facilities. As explained in section III.D.
(Air Quality and Attainment Status), most available information
indicates that winter ozone formation in the Basin is driven by local
emissions and is sensitive to changes in VOC emissions. There is
greater uncertainty as to the sensitivity to changes in NO<INF>X</INF>
emissions. As explained in section III.E. (Emissions Information),
available information indicates that 97 percent of anthropogenic VOC
emissions in the Basin are from existing oil and natural gas activity,
and that about 89 percent of those emissions are from existing sources
on the Indian country lands within the U&O Reservation and in the
nonattainment area. Before this rulemaking, VOC emissions control
requirements for existing oil and natural gas sources existed in areas
of the Basin where the EPA has approved the UDEQ to implement the CAA
but did not exist in Indian country lands within the U&O Reservation.
As explained in this final rulemaking and in the supporting information
in the record, VOC control requirements are necessary to protect air
quality on Indian country lands within the U&O Reservation.
The CAA does not require an attainment plan for Marginal ozone
nonattainment areas.\6\ Accordingly, this U&O FIP is not intended to
bring the Uinta Basin back into attainment with the ozone standard.
However, we do anticipate that this U&O FIP will make a meaningful
improvement in air quality through the reduction of VOC, an ozone
precursor, while also allowing continued construction authorization of
new development in the Basin and the positive economic impact that this
development brings to the Tribe.
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\6\ On March 9, 2018 (83 FR 10376), the EPA published the
Classifications Rule, which established how the statutory
classifications apply for the 2015 ozone NAAQS, including the air
quality thresholds for each classification category. Based on this
rule, each area with a 3-year design value of 71 ppb to 81 ppb,
based on monitoring data from 2014-2016, was to be classified as a
Marginal nonattainment area. The requirements for Marginal ozone
nonattainment areas are specified in CAA Title I, Part D, subpart 2
(see 42 U.S.C. 7511a(a)) and include: (1) Comprehensive, accurate,
current inventory of actual ozone precursor emissions from all
sources; (2) Corrections, if necessary, to existing implementation
plans to meet specific requirements, including for nonattainment
major source permitting; (3) Triennial emissions inventory updates;
and (4) General offset requirements for new and modified major
sources.
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This final action is driven by the EPA's authority and
responsibility to protect air quality in Indian country under sections
301(a) and 301(d)(4) of the CAA and 40 CFR 49.11. Regarding
preconstruction review of proposed new or modified sources \7\ of air
pollution in nonattainment areas in Indian country, the reviewing
authority must demonstrate that the minor source or modification would
not cause or contribute to a NAAQS violation in the nonattainment area
(see 40 CFR 49.155(a)(7)(ii)) \8\ and that preconstruction review of
new major stationary sources and major
[[Page 75336]]
modifications to existing major stationary sources located in an area
designated as nonattainment for any NAAQS would provide a net air
quality benefit in the nonattainment area (see 40 CFR 49.169(b)(4)).
While the CAA Indian country nonattainment permit program for major
sources specifies offset requirements as the method to make such a
demonstration (see 40 CFR 49.169(b)(3)), the CAA Indian country
nonattainment permit program for minor sources is not prescriptive as
to how to make such a demonstration. The requirements of this U&O FIP
will result in VOC emission reductions from existing sources,\9\
thereby improving air quality, and will also allow the EPA to rely on
those reductions to meet the NAAQS protection requirements for
continued construction authorization of new or modified minor sources
in the nonattainment area.
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\7\ 40 CFR 49.152 defines ``minor modification at a major
source,'' ``minor source,'' ``modification,'' ``synthetic minor
source,'' and ``true minor source,'' all of which are subject to the
permitting requirements of the Federal Minor New Source Review
Program in Indian Country, at 40 CFR 49.151-49.165.
\8\ 40 CFR 49.155 applies to your permit if you are subject to
this program under 40 CFR 49.153(a) for construction of a new minor
source, synthetic minor source or a modification at an existing
source.
\9\ Existing sources are sources that commence construction
before the effective date of this FIP, per 40 CFR 49.4169(c).
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This U&O FIP focuses on VOC emission reductions because
improvements in winter ozone levels in the Basin are most likely to
come from VOC emissions reductions from existing oil and natural gas
sources.\10\ Further, after a careful analysis of initial emissions
data provided by industry and later updated using information obtained
from two studies in the 2017 Uinta Basin Oil and Gas Emissions
Inventory Update (referred to herein as the UBEI2017-Update),\11\ we
determined that most of the existing oil and natural gas sources on the
Indian country lands within the U&O Reservation are largely
uncontrolled for VOC and other emissions. Therefore, in developing this
rule, we concentrated on determining the most effective control
requirements to reduce VOC emissions from oil and natural gas sources
to address the winter ozone exceedances. This is not to say that
reductions in NO<INF>X</INF> would not be beneficial in winter months.
The EPA may decide to focus on NO<INF>X</INF> reductions in future
rulemakings if additional action is required to address air quality
impacts from ozone pollution in the Basin.
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\10\ See Uinta Basin Ozone Studies (field studies conducted in
the Basin from 2011 to 2014), available at <a href="https://deq.utah.gov/air-quality/uinta-basin-ozone-studies-ubos">https://deq.utah.gov/air-quality/uinta-basin-ozone-studies-ubos</a>, accessed Mar. 11, 2022. The
RIA for this rule contains detailed discussion of the studies and
can be viewed in the docket for this rulemaking (Docket ID No. EPA-
R08-OAR-2015-0709).
\11\ 2017 Uinta Basin Oil and Natural Gas Emissions Inventory
Update (UBEI2017-Update). The inventory and supporting analysis can
be viewed in the docket for this rule, Microsoft Excel spreadsheet
titled, ``UO FIP cost and emissions analysis.xlsx'' (Docket ID No.
EPA-R08-OAR-2015-0709). The inventory covers sources in Uintah and
Duchesne Counties. The UDEQ submitted an earlier version of the 2017
inventory to the 2017 NEI and plans to submit the updated emissions
at a future date. The UDEQ, the EPA, and the Ute Indian Tribe
updated storage vessel, pneumatic controller, pneumatic pump,
fugitive, gas well liquid unloading, blowdowns and pigging and
oilfield wastewater emissions using updated emissions factors
obtained from the Uinta Basin Composition Study and the acquisition
of about 200 of oilfield wastewater (produced water) samples. The
studies that updated the emissions factors are described in two
White Papers available in the docket, ``UINTA BASIN VOC COMPOSITION
STUDY IMPACTS ON THE 2017 OIL AND GAS EMISSIONS INVENTORY November
2020--Revised March 2021--White Paper'' (``DAQ-2021-004302.pdf''),
and ``PRODUCED WATER DISPOSAL FACILITY EMISSION FACTORS & THEIR
IMPACT ON THE 2017 OIL AND GAS EMISSIONS INVENTORY November 2020--
Revised April 2021--White Paper'' (``DAQ-2020-016022.pdf'').
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Second, the control requirements being finalized are intended to be
the same as or consistent with the requirements applicable to similar
sources in areas of the Basin where the EPA has approved the UDEQ to
implement the CAA, to promote a more consistent regulatory environment
across the Basin. Where we are regulating existing equipment or
activities that are also covered by EPA standards for the oil and
natural gas source category, but do not meet the applicability criteria
of those standards, we also strove for consistency with those EPA
standards.
Finally, given the number of oil and natural gas projects in the
Basin that are already approved or are in the federal review and
approval process through evaluations conducted under the National
Environmental Policy Act (NEPA) by other federal agencies,\12\ in the
coming years the EPA could receive a large number of applications for
authorization to construct new and modified synthetic minor oil and
natural gas sources on Indian country lands within the U&O Reservation,
as well as registrations of new and modified true minor oil and natural
gas sources on Indian country lands within the U&O Reservation under
the Federal Implementation Plan for 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 (codified at 40
CFR part 49, subpart C, 40 CFR 49.101-49.105) \13\ (National O&NG FIP).
In addition to providing a streamlined construction authorization
mechanism to new and modified true minor oil and natural gas
sources,\14\ the National O&NG FIP requires compliance with a suite of
eight federal oil and natural gas source category emissions standards
\15\ for new and modified sources, as applicable. In 2019, the EPA
extended the National O&NG FIP's streamlined construction authorization
mechanism for true minor oil and natural gas sources in Indian country
to the portions of the U&O Reservation within the Uinta Basin ozone
nonattainment area.\16\ We are relying on the existing source VOC
emissions reductions that will be achieved under this U&O FIP to ensure
that the limited extension of the National O&NG FIP to the Indian
country portion of the Uinta Basin Ozone Nonattainment Area will not
harm the area's ability to attain the NAAQS. This is described in
greater detail in Sections V.C. and VI.B.
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\12\ Spreadsheet titled, ``Uinta Basin OG NEPA Evaluations
9.11.19.pdf,'' available in the Docket for this rulemaking (Docket
ID No. EPA-R08-OAR-2015-0709), lists oil and natural gas production
projects in the Uinta Basin that have been subject to evaluation
under NEPA.
\13\ Final Rule: Federal Implementation Plan for 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;
Amendments to the Federal Minor New Source Review Program in Indian
Country to Address Requirements for True Minor Sources in the Oil
and Natural Gas Sector, 81 FR 35944 (June 3, 2016); docket No. EPA-
HQ-OAR-2014-0606, available at <a href="https://www.regulations.gov">https://www.regulations.gov</a>, accessed
Mar. 11, 2022.
\14\ As defined in the Federal Minor New Source Review Program
in Indian Country at 40 CFR 49.152, a true minor source is a source
that emits or has the potential to emit regulated NSR pollutants in
amounts that are less than the major source thresholds in 40 CFR
49.167 (federal preconstruction permit program for major sources in
nonattainment areas in Indian country) or 40 CFR 52.21 (federal
preconstruction permit program for major sources in attainment/
unclassifiable areas), as applicable, but equal to or greater than
the minor NSR thresholds in 40 CFR 49.153 (federal preconstruction
permit program for minor sources in Indian country), without the
need to take an enforceable restriction to reduce its potential to
emit to such levels.
\15\ See 40 CFR 49.105. The National O&NG FIP specifies that
sources must comply with, as applicable, the following standards:
NESHAP 40 CFR part 63, subpart DDDDD; NESHAP 40 CFR part 63, subpart
ZZZZ; NSPS IIII 40 CFR part 60, subpart IIII; NSPS 40 CFR part 60,
subpart JJJJ; NSPS 40 CFR part 60, subpart Kb; NSPS 40 CFR part 60,
subpart OOOOa; NESHAP 40 CFR part 63, subpart HH; and NSPS 40 CFR
part 60, subpart KKKK.
\16\ Final Rule: Amendments to 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, 84 FR 21240 (May 14,
2019); Docket No. EPA-HQ-OAR-2014-0606, available at <a href="https://www.regulations.gov">https://www.regulations.gov</a>, accessed Mar. 11, 2022.
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In the preamble to the final National O&NG FIP published on June 3,
2016, the EPA stated that the most appropriate means for addressing air
quality concerns on specific reservations due to impacts from oil and
natural gas activity is through area- or reservation-specific FIPs, not
through the National O&NG FIP. Further, we stated that such FIPs may
need to include requirements for existing, new, and modified sources
[[Page 75337]]
beyond those in the National O&NG FIP.\17\ Consistent with that
approach, new and modified true minor oil and natural gas sources on
Indian country lands within the U&O Reservation that would use the
National O&NG FIP for construction authorization may have to comply
with additional requirements for certain equipment or activities not
covered by the eight federal standards.\18\
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\17\ See 81 FR 35964, 35968.
\18\ As described in detail later, this action exempts certain
equipment and activities that are subject to the emissions control
requirements of a subset of the eight federal standards in the
National O&NG FIP from having to comply with the emissions control
requirements in this action for the same equipment and activities.
Other types of equipment, such as small and remote glycol
dehydrators and storage vessels with potential emissions <= 6 tpy
VOC, are not regulated by those federal standards but are regulated
in this action.
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In summary, this U&O FIP is intended to: (1) improve air quality on
Indian country lands within the U&O Reservation; (2) promote a more
consistent regulatory environment across the Basin; and (3) ensure that
emissions reductions will be achieved that will ensure that new
development, under both source-specific minor source permitting and the
National O&NG FIP's streamlined construction authorization mechanism
for new or modified true minor oil and natural gas sources, will not
interfere with attainment of the NAAQS.
B. Summary of the Major Provisions of This Final Rule
The following is a summary of each key requirement in the final
action. As explained earlier, the final FIP was developed to maximize
air quality improvement, in a manner that promotes a more consistent
regulatory environment across all areas in the Uinta Basin, such that
covered sources within Indian country on the U&O Reservation will be
regulated in a manner similar to how they would be regulated if located
in areas in the Basin where EPA has approved the UDEQ to implement the
CAA. We attempted to achieve this goal by providing as much consistency
as possible in the FIP with current federal standards for the oil and
natural gas industry, including NSPS 40 CFR part 60, subparts OOOO and
OOOOa (NSPS OOOO and OOOOa); NESHAP 40 CFR part 63, subpart HH (NESHAP
HH); and the Control Techniques Guidelines for reducing smog-forming
VOC emissions from existing oil and natural gas equipment and processes
in certain states and areas with smog problems (Oil and Gas CTG).\19\
The provisions in the final U&O FIP are informed by EPA's evaluation of
these several applicable federal authorities as well as an evaluation
of current UDEQ requirements that apply in the Uinta Basin outside of
the Indian country lands within the U&O Reservation (areas of the Basin
where the EPA has approved the UDEQ to implement the CAA). Where the
EPA identified differences in these authorities, we considered the
facts specific to the U&O Reservation in conjunction with the goals of
the FIP to decide what to include in the final FIP. Our analysis was
somewhat complicated by a recent joint resolution under the
Congressional Review Act (CRA),\20\ which disapproved policy revisions
made in 2020 to NSPS OOOO and OOOOa \21\ and thereby reinstated
standards from the 2012 NSPS OOOO and 2016 NSPS OOOOa.\22\ The
resolution did not, however, disapprove technical revisions made in a
separate rulemaking in 2020 to NSPS OOOOa,\23\ which remain in place
today. These two events resulted in regulatory inconsistencies between
the NSPS OOOOa methane and VOC standards.\24\ Further, the Oil and Gas
CTG in some respects includes recommendations that do not match exactly
with the requirements in the 2016 NSPS OOOOa methane standards.\25\ In
addition, the EPA recently proposed a rule to regulate methane and VOC
emissions from existing, new, and modified sources in the oil and
natural gas industry that would revise existing standards under NSPS
OOOOa, establish new VOC and methane standards for emissions sources
not previously covered by NSPS OOOOa, and establish methane emissions
guidelines for existing sources (Oil and Natural Gas Sector Climate
Review Proposed Rule).\26\ As part of that proposed rule, the EPA
addressed the inconsistencies between the methane and VOC standards in
NSPS OOOOa by proposing to repeal certain NSPS OOOOa amendments that
were made in the 2020 Technical Rule.\27\ Despite these complications,
EPA has focused its analysis for this U&O FIP on the currently
applicable state and federal requirements and guidance.
---------------------------------------------------------------------------
\19\ Available at <a href="https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry/2016-control-techniques-guidelines-oil-and">https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry/2016-control-techniques-guidelines-oil-and</a>, accessed Mar. 11, 2022. CTGs are not regulations and do not
impose legal requirements directly on pollution sources; rather,
they provide recommendations for state and local air agencies to
consider as they determine what emissions limits to apply to covered
sources in their jurisdictions in order to meet RACT requirements.
\20\ 5 U.S.C. 801-808.
\21\ 85 FR 57018 (Sept. 14, 2020) (``2020 Policy Rule''; as of
June 30, 2021, no longer in effect due to CRA disapproval).
\22\ Public Law 17-23 (June 30, 2021) (resolving that Congress
``disapproves the [2020 Policy Rule] . . . and such rule shall have
no force or effect'').
\23\ 85 FR 57398 (Sept. 15, 2020) (``2020 Technical Rule'').
\24\ For requirements that currently apply, see Congressional
Review Act Resolution to Disapprove EPA's 2020 Oil and Gas Policy
Rule. Questions and Answers. U.S. Environmental Protections Agency.
Office of Air Quality Planning and Standards. June 30, 2021,
available at <a href="https://www.epa.gov/system/files/documents/2021-07/qa_cra_for_2020_oil_and_gas_policy_rule.6.30.2021.pdf">https://www.epa.gov/system/files/documents/2021-07/qa_cra_for_2020_oil_and_gas_policy_rule.6.30.2021.pdf</a>, accessed Mar.
11, 2022.
\25\ For example, while the CTG recommends exempting low-
production well sites from monitoring fugitive VOC emissions, the
current OOOOa methane standards do not have such exemption.
\26\ Proposed Rule. Standards of Performance for New,
Reconstructed, and Modified Sources and Emissions Guidelines for
Existing Sources: Oil and Natural Gas Sector Climate Review. See 86
FR 63110, November 15, 2021, available at <a href="https://www.regulations.gov">https://www.regulations.gov</a> (Document ID No. EPA-HQ-OAR-2021-0317-0001),
accessed Mar. 14, 2022. On the same day that this action is being
signed, the Administrator has also signed a supplemental notice
which proposes to update and expand on the 2021 Climate Review
proposal. See Supplemental notice of proposed rulemaking. Standards
of Performance for New, Reconstructed, and Modified Sources and
Emissions Guidelines for Existing Sources: Oil and Natural Gas
Sector Climate Review. Signed by the EPA Administrator on November
8, 2022, available at <a href="https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry/epa-issues-supplemental-proposal-reduce">https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry/epa-issues-supplemental-proposal-reduce</a>. Today's action discusses certain aspects of the 2021 Climate
Review proposal, but does not attempt to describe the 2022
supplemental proposal, in light of the concurrent signature of the
latter action.
\27\ For example, the EPA is proposing to repeal the 2020
Technical Rule amendments that exempted low-production well sites
from monitoring fugitive VOC emissions, and those that changed
fugitive VOC emissions monitoring requirements at gathering and
boosting compressor stations from quarterly to semi-annually. The
proposed rule would also establish an LDAR applicability threshold
for existing, new, and modified oil and natural gas well sites of 3
tpy site-wide methane fugitive emissions (and co-proposed an
alternative threshold of 8 tpy site-wide methane fugitive
emissions).
---------------------------------------------------------------------------
That said, we acknowledge that the Agency's thinking on these
issues has evolved since we issued NSPS OOOOa and the CTG in 2016.
Among other developments, new information and analysis have been
presented in the Oil and Natural Gas Sector Climate Review Proposed
Rule that will likely be relevant for reducing emissions on the U&O
Reservation. When the EPA proposed this FIP, however, the Agency had
not yet proposed that other rule, and the Climate Review Rule is still
being developed. In the interest of moving quickly to achieve emissions
reductions, the EPA finds that it is necessary and appropriate to
finalize this FIP now. Our assessment of new, potentially relevant
information will continue in the context of the Oil and Natural Gas
Sector Climate Review Rule. If we finalize that proposed national rule
in the future, its
[[Page 75338]]
requirements will apply directly to covered sources. As to sources not
covered by a final national rule, the EPA may find it necessary or
appropriate to revisit this final action in the future and revise this
FIP based on information evaluated in issuance of a final Climate
Review Rule, providing public notice of the opportunity for review and
comment on any such revisions as part of the required rulemaking
process. Also, if the Uinta Basin Ozone Nonattainment Area's Marginal
classification is reclassified (``bumped up'') to a Moderate
nonattainment classification, or if air quality concerns otherwise
warrant, we may conclude that further rulemaking is necessary or
appropriate.
General applicability: The final rule applies to owners or
operators of oil and natural gas sources that produce oil and natural
gas or process natural gas, that are located on Indian country lands
within the U&O Reservation, and that meet the applicability criteria
specified for each set of requirements. The final rule is effective 60
days after the date of publication in the Federal Register. For new and
modified sources that construct on or after the effective date of this
final rule, compliance is required upon startup. Compliance for
existing sources that commence construction before the effective date
of the final rule is required no later than 12 months after the
effective date of the final rule. The final rule allows owners or
operators to request approval, on a case-specific basis and prior to
the compliance deadline, of an extension of the compliance deadline for
existing sources.
Delegation of authority of administration to the Tribe: The final
rule contains provisions for the Ute Indian Tribe to request delegation
to assist the EPA with administration of the federal rule and the
process by which the EPA may delegate such authority.
Emissions inventory: The final rule requires that each owner and
operator of affected oil and natural gas sources with the potential to
emit one or more NSR-regulated pollutants at levels greater than or
equal to 1 tpy must submit an inventory of actual emissions for each
emissions unit to the EPA every three years that covers emissions from
the previous calendar year (OMB Control No. 2008--New (2539.02)). The
emissions inventory serves the purpose of the triennial collection of
comprehensive Uinta Basin oil and natural gas emissions by the EPA, the
Ute Indian Tribe, and UDEQ, and corresponds with the years that
emissions inventory information is collected for the EPA National
Emissions Inventory (NEI).\28\
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\28\ Information available at <a href="https://www.epa.gov/air-emissions-inventories/national-emissions-inventory-nei">https://www.epa.gov/air-emissions-inventories/national-emissions-inventory-nei</a>, accessed Mar. 11,
2022.
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Storage vessels, glycol dehydrators and pneumatic pumps: The final
rule contains federally enforceable requirements for owners and
operators of each existing, new, and modified oil and natural gas
source that has the potential to emit 4 tons per year of VOC or more
from the collection of all storage vessels, glycol dehydrators and
pneumatic pumps. The rule requires that each affected oil and natural
gas source collect and route all VOC emissions from each storage
vessels, glycol dehydrator and pneumatic pump through a closed-vent
system to 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 route them to a flare or other control device
designed and operated to achieve at least 95.0 percent continuous VOC
emissions control efficiency.
Covers and closed-vent systems: The final rule requires owners and
operators of affected existing, new, and modified oil and natural gas
sources that are required to control VOC emissions from the collection
of all storage vessels, glycol dehydrators and pneumatic pumps, to: use
covers on any affected storage vessels that ensure flashing, working,
standing, and breathing losses are efficiently captured; and to capture
and route emissions from any affected storage vessel, glycol dehydrator
and pneumatic pump through closed-vent systems with equipment that
ensures all VOC emissions make it to the respective process or VOC
emissions control device. The rule contains construction and
operational requirements that are intended to provide legal and
practicable enforceability to ensure that all captured emissions are
routed to their intended destination with no detectable emissions.
Control devices: The final rule contains legally and practicably
enforceable construction, work practice, and operational requirements
for each required flare or enclosed combustor. Each flare must be
designed and operated according to the requirements of 40 CFR 60.18(b).
Each enclosed combustor must be designed and operated to reduce the
mass content of the VOC in the natural gas routed to it by at least
95.0 percent on a continuous basis, and must be tested by the
manufacturer, owner, or operator in accordance with the requirements of
40 CFR part 60 subparts OOOO or OOOOa. Flares and enclosed combustors
must be operated within specific parameters to ensure the effective
control of VOC emissions (including requirements to be equipped and
operated with a liquid knockout system, a continuously burning pilot
flame or electronically controlled automatic ignition device, and a
monitoring system for continuous monitoring and recording of
operational parameters; maintained in a leak-free condition; and
operated with no visible smoke emissions).
Fugitive emissions: The final rule requires implementation of a
semi-annual leak detection and repair (LDAR) program for the collection
of fugitive emissions components at each oil and natural gas source
with facility-wide potential emissions from the collection of all
storage vessels, glycol dehydrators and pneumatic pumps equal to or
greater than 4 tpy VOC, plus any additional well sites with production
of more than 15 barrels of oil equivalent (boe) per day.\29\ The final
rule also contains provisions allowing for the use of alternative
methods of leak detection, provided the method is approved by the EPA.
---------------------------------------------------------------------------
\29\ As explained earlier, this FIP has been developed to
maximize air quality improvements in a manner that promotes a more
consistent regulatory environment across jurisdictional boundaries.
We evaluated several authorities to further these goals with respect
to fugitive emissions monitoring. The Oil and Gas CTG does not
recommend that well sites with production of less than 15 boe per
day (``low-production'' well sites) monitor fugitive emissions.
Using a different measure, the UDEQ applies LDAR requirements only
at well sites where the total actual uncontrolled VOC emissions from
the collection of storage vessels and glycol dehydrators is greater
than or equal to 4 tpy VOC (unless the well site is subject to the
LDAR requirements of NSPS OOOOa, in which case the operator would
comply with NSPS OOOOa).And as explained above, the NSPS OOOOa
requirements may be changed by the Oil and Natural Gas Sector
Climate Review Proposed Rule, which proposes to repeal some of the
amendments that were made to NSPS OOOOa as part of the 2020
Technical Rule. Among the provisions proposed for repeal are those
that exempted low-production well sites from fugitive emissions
monitoring and those that changed fugitive VOC monitoring
requirements at gathering and boosting compressor stations from
quarterly to semi-annually. Those fugitive VOC standards are still
in place today, and are in contrast to the 2016 fugitive methane
standards that were reinstated by the CRA disapproval of the 2020
Policy Rule. The proposed rule also would require quarterly
monitoring at oil and natural gas well sites of 3 tpy site-wide
methane fugitive emissions (and co-proposes semi-annual monitoring
for those with site-wide methane fugitive emissions between 3 and 8
tpy, with quarterly monitoring for those with site-wide methane
fugitive emissions above 8 tpy).
---------------------------------------------------------------------------
VOC emissions control requirements for all sources: The final rule
contains VOC control requirements for all existing, new, and modified
oil and natural gas sources, regardless of source-wide or emission unit
specific
[[Page 75339]]
applicability criteria. These requirements include: (1) tank trucks
transporting crude oil, condensate, intermediate hydrocarbon liquids or
produced water must be loaded using bottom filling or submerged fill
pipes; (2) all existing pneumatic controllers must meet the pneumatic
controller standards in NSPS OOOO; and (3) all existing enclosed
combustors and flares present and operating at sources on a voluntary
basis must be equipped with an electronically controlled automatic
ignition device.
Monitoring, recordkeeping, notification and reporting: This U&O FIP
requires owners or operators to conduct source monitoring sufficient to
demonstrate compliance with the FIP's VOC emission reduction and
control requirements, including: (1) monthly inspections of each cover
and closed-vent system to ensure proper condition and functioning and
to identify defects that can result in air emissions, correcting or
repairing any defects identified within 30 days of identification; and
(2) monthly inspections of each VOC emissions control device to ensure
proper functioning whenever an operator is on site, at least once per
calendar month, and responding to any indication of malfunction (e.g.,
pilot flame failure, visible emissions) as soon as practicably and
safely possible after discovery.
C. Costs and Benefits
The EPA has projected the compliance costs, emissions reductions,
and benefits that may result from the U&O FIP. The discussion of
projected costs and benefits is presented in detail in the Regulatory
Impacts Analysis (RIA) accompanying this final rule.\30\ The RIA
focuses on the elements of the final rule--the provisions related to
VOC emissions control requirements--that are likely to result in
quantifiable costs, emissions changes, and benefits compared to a
baseline that includes operator-reported emissions from oil and natural
gas sources in the Uinta Basin for calendar year 2017, specifically on
the Indian country lands within the U&O Reservation. We estimated the
effects of the final rule for all sources that are conservatively
projected \31\ to be subject to compliance activities under this action
for the analysis years 2023 through 2032. The RIA also presents the
present value (PV) and equivalent annualized value (EAV) of costs,
benefits and net benefits of this action in 2016 dollars.
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\30\ Available in the docket for this rulemaking (Docket ID No.
EPA-R08-OAR-2015-0709).
\31\ As explained throughout this preamble, and in the RIA, this
quantitative projection does not account for those sources that may
be exempt from certain requirements of the rule because they are
subject to equivalent requirements in NSPS OOOO or OOOOa, or in
NESHAP HH. Therefore, it is likely that costs for those sources will
be less for certain activities than for sources subject to
requirements of the FIP.
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A summary of the key results of this final rule is presented in
Table 1. Table 1 presents the PV and EAV, estimated using discount
rates of 7 and 3 percent, of the benefits, costs and net benefits, as
well as the change in emissions under the final rule. The monetized net
benefits are the benefits (emissions reductions) minus the costs
(annualized compliance costs). These results present an incomplete
overview of the effects of the final FIP, because categories of
benefits--including benefits from reducing other types of air
pollutants--were not monetized and are therefore not reflected in Table
1.
Table 1--Benefits, Costs, Net Benefits and Emissions Reductions of the Final Rule 2023 Through 2032
[Dollar estimates in millions of 2016 dollars] \a\
----------------------------------------------------------------------------------------------------------------
Equivalent Equivalent
Present value annual value Present value annual value
----------------------------------------------------------------------------------------------------------------
3 Percent Discount Rate
----------------------------------------------------------------------------------------------------------------
Benefits \b\.................................... $1,000 $120 $1,000 $120
----------------------------------------------------------------------------------------------------------------
3 Percent Discount Rate
7 Percent Discount Rate
---------------------------------------------------------------
Net Compliance Costs............................ 610 72 560 81
Compliance Costs............................ 630 74 580 83
Product Recovery............................ 20 2 20 2
Net Benefits.................................... 390 48 440 39
----------------------------------------------------------------------------------------------------------------
Non-Monetized Benefits \c\...................... Ozone health and climate benefits from reducing 23,000 tons of
VOC/year and ozone health benefits from 59,000 tons of methane/
year from 2023 to 2032.
---------------------------------------------------------------
Ozone health and PM2.5 benefits from reducing 23,000 tons of
VOC/year from 2023 to 2032.
---------------------------------------------------------------
HAP benefits from reducing 3,100 tons of HAP/year from 2023 to
2032 (including 570 tons of benzene, 970 tons of toluene, 130
tons of ethylbenzene, 620 tons of xylenes and 770 tons of n-
hexane per year).
---------------------------------------------------------------
Visibility benefits.
---------------------------------------------------------------
Reduced vegetation effects from exposure to ozone.
----------------------------------------------------------------------------------------------------------------
\a\ Values rounded to two significant figures. Totals may not appear to add correctly due to rounding.
[[Page 75340]]
\b\ Monetized benefits of the final rule include climate benefits associated with reductions in methane
emissions and are calculated using four different estimates of the social cost of methane (SC-CH4) (model
average at 2.5 percent, 3 percent, and 5 percent discount rates: 95th percentile at 3 percent discount rate).
For the presentational purposes of this table, we show the benefits associated with the average SC-CH4 at a 3
percent discount rate, but the Agency does not have a single central SC-CH4 point estimate. We emphasize the
importance and value of considering the benefits calculated using all four SC-CH4 estimates; the present value
(and equivalent annual value) of the additional benefit estimates (millions of 2016$) ranges from $480 to
$2,700 ($62 to $310) over 2023 to 2032 for the final rule. Please see Table 6-6 of the RIA for the full range
of SC-CH4 estimates. As discussed in Section 6.5 of the RIA, a consideration of climate benefits calculated
using discount rates below 3 percent, including 2 percent and lower, are also warranted when discounting
intergenerational impacts. All net benefits are calculated using climate benefits discounted at 3 percent.
\c\ There are important unquantified health and welfare benefits associated with reductions in other air
pollutants, which are discussed in Chapter 6 of the RIA.
This final rule is expected to result in net benefits (emissions
reductions) for human health and the environment in the Uinta Basin.
The estimated benefits include the monetized climate effects of the
projected reduction in methane emissions under the final rule resulting
from the targeted reduction of VOC emissions. The PV of these climate-
related benefits (emissions reductions), discounted at a 3-percent
rate, is estimated to be about $1 billion, with an EAV of about $120
million (Table 1).
In addition to directly controlling VOC emissions, which are
expected to lower ozone concentrations in the Uinta Basin, this action
is expected to lower HAP emissions and the formation of secondary
particulate matter with a diameter of 2.5 micrometers or less
(PM<INF>2.5</INF>) even though those pollutants are not directly
regulated under this action. While the EPA expects that the VOC
emissions reductions will improve air quality and have beneficial
health and welfare effects associated with reduced exposure to ozone,
PM<INF>2.5</INF>, and HAP, we did not quantify those effects. We note
that the absence of those monetized benefits from the analysis of
benefits does not imply that these benefits do not exist, but also has
no bearing on the legal or technical basis for the final action itself.
We qualitatively discuss these unquantified benefits in Chapter 6 of
the RIA. If the EPA were to quantify the ozone and PM<INF>2.5</INF>
impacts, the Agency would estimate the number and value of avoided
premature deaths and illnesses using an approach detailed in the
Particulate Matter NAAQS and Ozone NAAQS RIA.\32\ Such an analysis
would account for the distribution of air pollution-attributable risks
among populations most vulnerable and susceptible to PM<INF>2.5</INF>
and ozone exposure. As explained in the RIA for this final rule, due to
methodology and data limitations for areas experiencing elevated winter
ozone, we were unable to estimate the benefits associated with ozone,
PM<INF>2.5</INF>, and HAP emission changes that would occur as a result
of this rule, but the EPA continues to develop better methods for
analyzing the benefits of such reductions.
---------------------------------------------------------------------------
\32\ U.S. EPA. Integrated Science Assessment (ISA) for
Particulate Matter (Final Report). EPA Office of Research and
Development (ORD), National Center for Environmental Assessment,
EPA/600/R-19/188 (Dec. 2019); available at: <a href="https://www.epa.gov/naaqs/particulate-matter-pm-standards-integrated-science-assessments-current-review">https://www.epa.gov/naaqs/particulate-matter-pm-standards-integrated-science-assessments-current-review</a>, accessed Mar. 11, 2022, and U.S. EPA.
Integrated Science Assessment for Ozone and Related Photochemical
Oxidants. EPA ORD, EPA/600/R-20/012 (Apr. 2020); available at:
<a href="https://www.epa.gov/isa/integrated-science-assessment-isa-ozone-and-related-photochemical-oxidants">https://www.epa.gov/isa/integrated-science-assessment-isa-ozone-and-related-photochemical-oxidants</a>. Accessed Mar. 11, 2022.
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The estimated capital and annualized compliance costs include the
monetized costs for affected owners or operators to comply with the
final rule. The net PV of these compliance costs (accounting for
product recovery), discounted at a 7-percent rate, is estimated to be
about $560 million, with an EAV of about $81 million (Table 1). Under a
3-percent discount rate, the PV of the compliance costs is about $610
million, with an EAV of about $72 million (Table 1).
The PV of the net benefits of this rule, discounted at a 7-percent
rate, is estimated to be about $440 million, with an EAV of about $39
million (Table 1). Under a 3-percent discount rate, the PV of net
benefits is about $390 million, with an EAV of about $48 million (Table
1).
II. General Information
A. Does this action apply to me?
Entities potentially affected by this rule include the Ute Indian
Tribe,\33\ as well as existing, new, and modified sources \34\ that are
in the oil and natural gas production and natural gas processing
segments of the oil and natural gas industry (see Table 2.) and are on
Indian country \35\ lands within the U&O Reservation. All of the Ute
Indian Tribe Indian country lands of which the EPA is aware are located
within the exterior boundaries of the Reservation, and this U&O FIP
applies to all such lands. To the extent that there are Ute Indian
Tribe Dependent Indian Communities under 18 U.S.C. 1151(b) or allotted
lands under 18 U.S.C. 1151(c) that are located outside the exterior
boundaries of the Reservation, those lands are not covered by this U&O
FIP.\36\ In addition, this rule does not apply to any sources on non-
Indian-country lands, including any non-Indian country lands within the
exterior boundaries of the Reservation.\37\
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\33\ The Ute Indian Tribe is a federally recognized tribe
organized under the Indian Reorganization Act of 1934, with a
Constitution and By-Laws adopted by the Tribe on December 19, 1936
and approved by the Secretary of the Interior on January 19, 1937.
See Indian Entities Recognized and Eligible to Receive Services from
the United States Bureau of Indian Affairs, See 82 FR 4915 (Jan. 17,
2017); 48 Stat. 984, 25 U.S.C.5123 (IRA); Constitution and By-Laws
of the Ute Indian Tribe of the Uintah and Ouray Reservation.
\34\ As specified at 40 CFR 49.4169(c).
\35\ Indian country is defined at 18 U.S.C. 1151 as: (a) all
land within the limits of any Indian reservation under the
jurisdiction of the United States Government, notwithstanding the
issuance of any patent, and, including rights-of-way running through
the reservation, (b) all dependent Indian communities within the
borders of the United States whether within the original or
subsequently acquired territory thereof, and whether within or
without the limits of a state, and (c) all Indian allotments, the
Indian titles to which have not been extinguished, including rights-
of-way running through the same.
\36\ Under the CAA, lands held in trust for the use of an Indian
tribe are reservation lands within the definition at 18
U.S.C.1151(a), regardless of whether the land is formally designated
as a reservation. See Indian Tribes: Air Quality Planning and
Management, See 63 FR 7254, 7258 (Feb. 12, 1998) (``Tribal Authority
Rule''); Arizona Pub. Serv. Co. v. EPA, 211 F.3d 1280, 1285-86 (D.C.
Cir. 2000). The EPA's references in this U&O FIP to Indian country
lands within the exterior boundaries of the U&O Reservation include
any such Tribal trust lands that may be acquired by the Ute Indian
Tribe.
In 2014, the U.S. Court of Appeals for the D.C. Circuit
addressed the EPA's authority to promulgate a FIP establishing
certain CAA permitting programs in Indian country. Oklahoma Dept. of
Environmental Quality v. EPA, 740 F. 3d 185 (D.C. Cir. 2014). In
that case, the court recognized the EPA's authority to promulgate a
FIP to directly administer CAA programs on Indian reservations but
invalidated the FIP at issue as applied to non-reservation areas of
Indian country in the absence of a demonstration of an Indian
tribe's jurisdiction over such non-reservation area. Because the
final rule would apply only on Indian country lands that are within
the exterior boundaries of the U&O Reservation, i.e., on Reservation
lands, it is unaffected by the Oklahoma court decision.
\37\ As a result of a series of federal court decisions, there
are some non-Indian country lands within the exterior boundaries of
the Uintah and Ouray Indian Reservation. See footnote 40.
[[Page 75341]]
Table 2--Source Categories Affected by This Action
----------------------------------------------------------------------------------------------------------------
Examples of regulated entities/description of
Industry category NAICS code industry category
----------------------------------------------------------------------------------------------------------------
Oil and Gas Production/Operations........ 21111 Exploration for crude petroleum and natural gas;
drilling, completing, and equipping wells; operation
of separators, emulsion breakers, desilting
equipment, and field gathering lines for crude
petroleum and natural gas; and all other activities
in the preparation of oil and gas up to the point of
shipment from the producing property.
Production of crude petroleum, the mining and
extraction of oil from oil shale and oil sands, the
production of natural gas, sulfur recovery from
natural gas, and the recovery of hydrocarbon liquids
from oil and gas field gases.
Crude Petroleum and Natural Gas 211111 Exploration, development and/or the production of
Extraction. petroleum or natural gas from wells in which the
hydrocarbons will initially flow or can be produced
using normal pumping techniques or production of
crude petroleum from surface shales or tar sands or
from reservoirs in which the hydrocarbons are
semisolids
Natural Gas Liquid Extraction............ 211112 Recovery of liquid hydrocarbons from oil and gas
field gases; and sulfur recovery from natural gas.
Drilling Oil and Gas Wells............... 213111 Drilling oil and gas wells for others on a contract
or fee basis, including spudding in, drilling in,
redrilling, and directional drilling.
Support Activities for Oil and Gas 213112 Performing support activities on a contract or fee
Operations. basis for oil and gas operations (except site
preparation and related construction activities)
such as exploration (except geophysical surveying
and mapping); excavating slush pits and cellars,
well surveying; running, cutting, and pulling
casings, tubes, and rods; cementing wells, shooting
wells; perforating well casings; acidizing and
chemically treating wells; and cleaning out,
bailing, and swabbing wells.
----------------------------------------------------------------------------------------------------------------
This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be regulated by this
action. This table lists the types of entities that the EPA is now
aware could potentially be regulated by this action. Other types of
entities not listed in the table could also be regulated. To determine
whether your entity is regulated by this action, you should carefully
examine the applicability criteria found in 40 CFR 49.4169 through
49.4184. If you have any questions regarding the applicability of this
action to a particular entity, contact the appropriate person listed in
the FOR FURTHER INFORMATION CONTACT section.
B. Where can I get a copy of this document and other related
information?
In addition to being available in the docket, an electronic copy of
this final action will also be posted at: <a href="https://www.epa.gov/air-quality-implementation-plans/approved-air-quality-implementation-plans-region-8">https://www.epa.gov/air-quality-implementation-plans/approved-air-quality-implementation-plans-region-8</a> (Approved Air Quality Implementation Plans in Region 8 page).
C. Judicial Review
Under section 307(b)(1) of the Act, petitions for judicial review
of this action must be filed in the United States Court of Appeals for
the appropriate circuit by February 6, 2023. Filing a petition for
reconsideration by the Administrator of this final rule does not affect
the finality of this rule for the purposes of judicial review nor does
it extend the time within which a petition for judicial review may be
filed and shall not postpone the effectiveness of such rule or action.
Under section 307(b)(2) of the Act, the requirements of this final
action with respect to which review could have been obtained under
section 307(b)(1) of the Act may not be judicially reviewed later in
civil or criminal proceedings brought by us to enforce these
requirements.
III. Background
A. Uintah and Ouray Indian Reservation
The Uintah and Ouray Indian Reservation is composed of lands that
were part of the original Uintah Valley and Uncompahgre Reservations,
which were established by executive order in 1861 and 1882,
respectively.\38\ In 1948 Congress extended the exterior boundary of
the Reservation with the Hill Creek Extension.\39\ The U&O
Reservation's boundaries have been addressed and explained in a series
of federal court decisions. Consistent with those decisions, the EPA
considers all lands within the U&O Reservation's boundaries to be
``Indian country'' as defined in 18 U.S.C. 1151, subject to federal
court decisions holding that specified Congressional acts removed
certain lands from Indian country status.\40\
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\38\ See Exec. Order of Oct. 3, 1861, reprinted in 1 Charles J.
Kappler, Indian Affairs: Laws and Treaties 900 (1904); confirmed by
Congress in the Act of May 5, 1864, ch. 77, 13 Stat. 63; Exec. Order
of Jan. 5, 1882, reprinted in Indian Affairs: Laws and Treaties at
901; U.S. Office of Indian Affairs, Dept. of the Interior, Annual
Report of the Commissioner of Indian Affairs, at 226 (1886).
\39\ 62 Stat. 72 (1948).
\40\ See Ute Indian Tribe v. Utah, 521 F. Supp. 1072 (D. Utah
1981); Ute Indian Tribe v. Utah, 716 F.2d 1298 (10th Cir. 1983); Ute
Indian Tribe v. Utah, 773 F.2d 1087 (10th Cir. 1985) (en banc),
cert. denied, 479 U.S. 994 (1986); Hagen v. Utah, 510 U.S. 399
(1994); Ute Indian Tribe v. Utah, 935 F. Supp. 1473 (D. Utah 1996);
Ute Indian Tribe v. Utah, 114 F.3d 1513 (10th Cir. 1997), cert.
denied, 522 U.S. 1107 (1998); Ute Indian Tribe v. Utah, 790 F.3d
1000 (10th Cir. 2015), cert. denied, 136 S. Ct. 1451 (2016); and Ute
Indian Tribe v. Myton, 835 F.3d 1255 (10th Cir. 2016), cert.
dismissed, 137 S. Ct. 2328 (2017); Hackford v. Utah, 845 F.3d 1325,
1327 (10th Cir.), cert. denied, 138 S. Ct. 206 (2017).
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B. Tribal Authority Rule
Section 301(d) of the CAA authorizes the EPA to treat Indian tribes
in the same manner as states for purposes of implementing the CAA over
their entire reservations and over any other areas within their
jurisdiction, and directs the EPA to promulgate regulations specifying
those provisions of the CAA for which such treatment is
appropriate.\41\ It also authorizes the EPA, when the EPA determines
that the treatment of Indian tribes as identical to states is
inappropriate or administratively infeasible, to provide by regulation
other means by which the EPA will directly administer the CAA.\42\
Acting principally under that authority, on February 12, 1998, the EPA
promulgated the Tribal Authority Rule (TAR).\43\ In the TAR, we
determined that it was appropriate to treat eligible tribes in the same
manner as states for
[[Page 75342]]
all CAA statutory and regulatory purposes, except a list of specified
CAA provisions and implementing regulations thereunder.\44\ That list
of excluded provisions includes specific plan submittal and
implementation deadlines for NAAQS-related requirements, among them the
CAA section 110(a)(2)(C) requirement to submit a program (including a
permit program as required in parts C and D of the CAA) to regulate the
modification and construction of any stationary source as necessary to
assure that the NAAQS are achieved. Other provisions for which we
determined that we would not treat tribes in the same manner as states
include CAA section 110(a)(1) (SIP submittal) and CAA section 110(c)(1)
(directing the EPA to promulgate a FIP ``within 2 years'' after we find
that a state has failed to submit a required plan or has submitted an
incomplete plan, or within 2 years after we disapprove all or a portion
of a plan).
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\41\ 42 U.S.C. 7601(d)(1) and (2); See 63 FR 7254-57 (Feb. 12,
1998) (explaining that CAA section 301(d) includes a delegation of
authority from Congress to eligible Indian tribes to implement CAA
programs over all air resources within the exterior boundaries of
their Reservations).
\42\ 42 U.S.C. 7601(d)(4).
\43\ ``Indian Tribes: Air Quality Planning and Management.'' see
63 FR 7254 (Feb. 12, 1998); 40 CFR 49.1-49.11.
\44\ 40 CFR 49.3-.4. To be eligible for treatment in a similar
manner as a state (TAS) under the Tribal Authority Rule, a tribe
must meet four requirements: (1) be a federally recognized tribe;
(2) have a governing body carrying out substantial governmental
duties and functions; (3) propose to carry out functions pertaining
to the management and protection of air resources of the tribe's
reservation or other areas within the tribe's jurisdiction; and (4)
be reasonably expected to be capable of carrying out the functions.
40 CFR 49.6. A tribe interested in administering a particular CAA
program or function may apply to the appropriate regional
administrator for a determination of whether it meets these TAS
eligibility criteria with respect to that program or function. 40
CFR 49.7.
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The TAR preamble clarified that by including CAA section 110(c)(1)
on the list at 40 CFR 49.4, the ``EPA is not relieved of its general
obligation under the CAA to ensure the protection of air quality
throughout the nation, including throughout Indian country.'' \45\ The
preamble confirmed that the ``EPA will continue to be subject to the
basic requirement to issue a FIP for affected tribal areas within some
reasonable time.'' \46\ Consistent with those statements, the TAR
includes a provision requiring the EPA to ``promulgate without
unreasonable delay such Federal implementation plan provisions as are
necessary or appropriate to protect air quality,'' unless a complete
TIP is submitted or approved.\47\
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\45\ See 63 FR at 7265 (Feb. 12, 1998).
\46\ Id.
\47\ 40 CFR 49.11(a).
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The Ute Indian Tribe has not applied for treatment in a similar
manner as a state (TAS) for the purpose of administering a TIP under
the CAA; nor has it submitted a TIP for review and approval. Thus, with
respect to Indian country lands within the U&O Reservation, there is
currently no submitted or EPA-approved TIP that would address the air
quality purposes described earlier. This FIP provides such a plan and
applies to all Indian country lands within the exterior boundaries of
the U&O Reservation.
C. Federal Indian Country Minor NSR Rule
1. What is the Federal Indian Country Minor NSR rule?
In 2006, acting under the authority provided in CAA section 301(d)
and in the TAR, we proposed the FIP regulation: ``Review of New Sources
and Modifications in Indian Country'' (Indian Country NSR rule).\48\ As
a part of this regulation, the EPA made a finding that it was necessary
or appropriate to protect air quality by developing a FIP to establish
a program to regulate the modification and construction of minor
stationary sources consistent with the requirements of section
110(a)(2)(c) of the CAA, where there was no EPA-approved tribal minor
NSR permit program in Indian country to regulate construction of new
and modified minor sources and minor modifications of major sources. We
call this part of the Indian Country NSR rule the Federal Indian
Country Minor NSR rule. In developing that FIP, we sought to
``establish a flexible preconstruction permitting program for minor
sources in Indian country that is comparable to similar programs in
neighboring states in order to create a more consistent regulatory
environment for owners/operators within and outside of Indian
country.'' \49\ The Federal Indian Country Minor NSR rule provides a
mechanism for issuing preconstruction permits for the construction of
new minor sources and certain modifications of major and minor sources
in areas covered by the rule. In developing the rule, the EPA conducted
extensive outreach and consultation, along with a 7-month public
comment period that ended on March 20, 2007. The comments provided
detailed information specific to Indian country, and the final Federal
Indian Country Minor NSR rule incorporated many of the suggestions we
received. We promulgated a final rule on July 1, 2011, and the FIP
became effective on August 30, 2011. \50\
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\48\ ``Review of New Sources and Modifications in Indian
Country,'' Proposed Rule, 71 FR 48696 (Aug. 21, 2006).
\49\ ``Review of New Sources and Modifications in Indian
Country,'' Final Rule, 76 FR 38748, 38754 (July 1, 2011).
\50\ See 76 FR 38748.
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The Federal Indian Country Minor NSR rule applies to existing, new,
and modified minor stationary sources and to minor modifications at
existing major stationary sources in Indian country where there is no
EPA-approved program in place. \51\ Tribes can elect to develop and
implement their own EPA-approved program under the TAR but are not
required to do so.\52\ In the absence of an EPA-authorized program, the
EPA implements the program. Tribes can request administrative
delegation of the federal program from the EPA and may be authorized by
the EPA to implement agreed-upon rules or provisions on behalf of the
Agency.
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\51\ 40 CFR 49.153. Existing sources are only subject to the
registration requirements unless they undergo modification.
\52\ To be eligible to develop and implement an EPA-approved
program, under the Tribal Authority Rule a tribe must meet four
requirements: (1) be a federally-recognized tribe; (2) have a
functioning government carrying out substantial duties and powers;
(3) propose to carry out functions pertaining to air resources of
the reservation or other areas within the tribe's jurisdiction; and
(4) be reasonably expected to be capable of carrying out the
program. See 40 CFR 40 CFR 49.1-49.11. Tribes can also establish
permit fees under a tribal permitting program pursuant to tribal
law, as do most states.
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Any existing, new, or modified stationary oil and natural gas
source that emits or has the potential to emit (PTE) a regulated NSR
pollutant in amounts equal to or greater than the minor NSR thresholds
in the Federal Indian Country Minor NSR rule, but less than the amount
that would qualify the source as a major source or a major modification
for purposes of the PSD or nonattainment major NSR programs, must
submit a registration form to the EPA containing information on, among
other things, source-wide actual emissions of NSR regulated pollutants,
information on the methods used to calculate the emissions, and
descriptions of the various emitting activities and equipment operated
at the source. Existing, new, and modified oil and natural gas sources
that commenced construction before October 3, 2016, complied with the
Federal Indian Country Minor NSR Permit Program by registering under
the Existing Source Registration Program at 40 CFR 49.160. Beginning
October 3, 2016, the owner/operator of any new true minor oil and
natural gas source must comply with the National O&NG FIP or apply for
and obtain a site-specific true minor NSR permit before beginning
construction. Likewise, the owner/operator of any existing stationary
source (minor or major) must comply with the National O&NG FIP or apply
for and obtain a minor NSR permit before beginning construction of a
physical or operational
[[Page 75343]]
change that will increase the allowable emissions of the stationary
source in amounts equal to or above the specified threshold amounts, if
the change does not otherwise trigger PSD or nonattainment major or
minor NSR permitting requirements.\53\
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\53\ A source may, however, be subject to certain monitoring,
recordkeeping, and reporting (MRR) requirements under the major NSR
program, if the change has a reasonable possibility of resulting in
a major modification. A source may be subject to both the Federal
Indian Country Minor NSR rule and the MRR requirements of the major
NSR program.
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2. What are the minor NSR thresholds?
The ``minor NSR thresholds'' establish cutoff levels for each
regulated NSR pollutant. If a source has a PTE in amounts lower than
the minor NSR thresholds,\54\ then it is exempt from the Federal Indian
Country Minor NSR rule for that pollutant. New or modified sources that
have a PTE in amounts that are: (1) equal to or greater than the minor
NSR thresholds; and (2) less than the major NSR thresholds (generally
100 or 250 tons per year (tpy)) are ``minor sources'' of emissions and
subject to the Federal Indian Country Minor NSR rule requirements at 40
CFR 49.151 through 49.161. Modifications at existing major sources that
have PTE equal to or greater than the minor NSR thresholds, but less
than the major NSR significant emission rates (range 10-100 tpy,
depending on the pollutant) are also ``minor sources'' of emissions and
subject to the Federal Indian Country Minor NSR rule requirements.
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\54\ See 40 CFR 49.153, Table 1.
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The minor NSR thresholds for VOC emissions for sources in Indian
country are 2 tpy in nonattainment areas and 5 tpy in attainment and
unclassifiable areas. Portions of the U&O Reservation are currently
designated unclassifiable for the 2008 ozone NAAQS and the minor NSR
thresholds for VOC are 5 tpy in those Indian country portions of the
Reservation. As discussed previously and further in Section D (Air
Quality and Attainment Status), other portions of the U&O Reservation
are included in the Uinta Basin Ozone Nonattainment Area, and,
therefore, the minor NSR thresholds for VOC are 2 tpy in those Indian
country portions of the Reservation.
D. Air Quality and Attainment Status
With respect to air quality, ozone levels in the Uinta Basin, in
which the U&O Reservation is located, have reached unhealthy levels
that warrant action. The 2015 8-hour ozone NAAQS is 70 parts per
billion (ppb).\55\ Compliance with the NAAQS is determined by
comparison to a ``design value'' based on a three-year average of the
fourth highest daily maximum 8-hour average ozone levels measured in a
year at each monitoring site. The state of Utah, the National Park
Service (NPS), and the Ute Indian Tribe operate ozone,
PM<INF>2.5,</INF> and NO<INF>2</INF> monitors in and around the Uinta
Basin. The ambient air concentrations measured at some of these
stations show that ozone levels in the Uinta Basin have repeatedly
violated both the 2008 and 2015 ozone NAAQS. Based on 2012-2020
regulatory air quality monitoring data, ozone design values exceed the
2015 ozone NAAQS at five monitoring sites in the Uinta Basin. The
highest valid ozone design value in the Uinta Basin for the three-year
period from 2017 to 2019 was from the Ouray monitor at 89 ppb.\56\ The
current (three-year period from 2018 to 2020) highest valid ozone
design value in the Uinta Basin is also from the Ouray monitor at 76
ppb. Additionally, higher single 8-hour average ozone concentrations
were observed at some monitoring sites, before the sites were
designated as regulatory monitors.\57\ For example, 8-hour average
ozone concentrations reached values as high as 141 ppb at the Ouray
monitor in March 2013. This concentration corresponds to an Air Quality
Index value of 211, which is characterized as ``Very Unhealthy.'' \58\
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\55\ See 80 FR 65292 (Oct. 26, 2015).
\56\ Valid design values are the regulatory statistic to
determine compliance with a NAAQS. They are calculated in accordance
with the appropriate NAAQS-specific appendix to 40 CFR part 50. For
the 2008 Ozone NAAQS (75 ppb), the appropriate appendix is 40 CFR
part 50, appendix P, and for the 2015 Ozone NAAQS (70 ppb) it is 40
CFR part 50, appendix U. Regulatory ozone data is available at
<a href="https://www.epa.gov/air-trends/ozone-trends">https://www.epa.gov/air-trends/ozone-trends</a>, accessed Mar. 14, 2022.
\57\ A ``regulatory'' monitor is a monitor that meets the EPA's
air quality monitoring requirements, including requirements for
siting, equipment selection, data sampling protocols, and quality
assurance, under the EPA's monitoring regulations at 40 CFR part 58.
\58\ The Air Quality Index (AQI) is a normalized system to allow
the public to compare health risks of different air pollutants on a
common scale. The AQI is divided into six levels of health concern:
Good, Moderate, Unhealthy for Sensitive Groups, Unhealthy, Very
Unhealthy, and Hazardous.
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As discussed previously, the EPA designated areas in the Uinta
Basin below 6,250 feet, including portions of the Indian country lands
within the U&O Reservation, as marginal nonattainment for the 2015
ozone standard. The fourth maximum ambient air concentration
measurement for 2020, the attainment year, is 66 ppb, which is lower
than the 2015 ozone NAAQS. Accordingly, Utah and the Ute Indian Tribe
requested to extend the August 3, 2021, attainment date for the Uinta
Basin Ozone Nonattainment Area by 1-year. On April 13, 2022, the EPA
proposed to grant a 1-year attainment date extension for the Uintah
Basin Ozone Nonattainment area.\59\ The proposal explains that
preliminary 2021 ozone monitoring data indicate that the area may not
attain the 2015 ozone NAAQS by the proposed extended attainment date of
August 3, 2022, but that the area could meet the air quality criteria
for a second 1-year extension. As of February 9, 2022, the Uinta Basin
area's preliminary 2019-2021 design value was 78 ppb and the
preliminary 2021 fourth highest daily maximum 8-hour concentration
value was 72 ppb. To qualify for a second 1-year extension, an area's
fourth highest daily maximum 8-hour value, averaged over both the
original attainment year and the first extension year, must be 70 ppb
or less (40 CFR 51.1307(a)(2)). If the preliminary 2021 ozone data are
certified, then the fourth highest daily maximum 8-hour value, averaged
over 2020 and 2021, would be 69 ppb. \60\ The EPA is issuing this
notice of final rulemaking (NFRM) because we have concluded that it is
necessary and appropriate to take action to protect air quality on the
Indian country lands within the U&O Reservation to address these
elevated ozone levels.
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\59\ See 87 FR 21842 (Apr. 13, 2022), available at <a href="https://www.govinfo.gov/content/pkg/FR-2022-04-13/pdf/2022-07513.pdf">https://www.govinfo.gov/content/pkg/FR-2022-04-13/pdf/2022-07513.pdf</a>,
accessed Apr. 29, 2022. The criteria to qualify for requesting a 1-
year extension of the attainment date are: (1) the state has
complied with all requirements and commitments pertaining to the
area in the applicable implementation plan; and (2) for a first
attainment date extension, an area's fourth highest daily maximum 8-
hour value for the attainment year must not exceed the level of the
standard.
\60\ Preliminary air quality data is available at <a href="https://www.epa.gov/outdoor-air-quality-data/download-daily-data">https://www.epa.gov/outdoor-air-quality-data/download-daily-data</a>, accessed
Apr. 29, 2022.
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Ambient ozone is a secondary pollutant formed when the two primary
ozone precursors, VOC and NO<INF>X</INF>, react in the presence of
sunlight. Air quality data and studies in the Uinta Basin show that
winter ozone levels above the NAAQS are due to a combination of
abundant local ground-level emissions of VOC and NO<INF>X</INF> with
the unique meteorological and topographic features in the Uinta Basin:
strong and persistent temperature inversions forming over snow-covered
ground, and elevated terrain completely surrounding a low basin. The
stable atmosphere allows the emissions to accumulate and react with
sunlight but prevents the emissions from escaping the temperature
inversion layer and dispersing. Therefore, ozone continues to form
while the unique meteorological conditions persist.\61\ The
[[Page 75344]]
state of Utah conducted field studies in the Uinta Basin from 2011 to
2014 to understand the emissions sources and the unique photochemical
processes that contribute to winter ozone concentrations within the
Uinta Basin. Reports for winter ozone field studies for each year are
available on the UDEQ website.\62\ These studies found that the oil and
natural gas production industry is the most significant anthropogenic
contributor of VOC and NO<INF>X</INF> emissions in the Basin and
primarily responsible for winter ozone formation. The studies also
concluded that winter ozone production in the Basin is sensitive to
changes in VOC emissions, and that there is greater uncertainty about
its sensitivity to changes in NO<INF>X</INF> emissions.
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\61\ The RIA for this final rule contains a more detailed
discussion of winter ozone and can be viewed in the docket for this
rulemaking (Docket ID No. EPA-R08-OAR-2015-0709).
\62\ ``Uinta Basin Ozone Studies (UBOS),'' <a href="https://deq.utah.gov/air-quality/uinta-basin-ozone-studies-ubos">https://deq.utah.gov/air-quality/uinta-basin-ozone-studies-ubos</a>, accessed Mar. 11, 2022.
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The EPA has determined that this final action will result in large
reductions of VOC emissions, and that this result is expected to reduce
ambient ozone and reduce the severity of exceedances of the 2008 and
2015 ozone NAAQS.\63\ As discussed in more detail later, the final
action includes a requirement for owners/operators to submit emissions
inventories on a triennial basis. This information will enable the
successful partnership to continue among the EPA, the UDEQ, the Tribe
and industry in maintaining an accurate oil and natural gas emissions
inventory for the Uinta Basin to be used, in part, as a tool for
managing the Basin's air quality.
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\63\ As discussed in the RIA for this final rule (available at
<a href="https://www.regulations.gov">https://www.regulations.gov</a>, Docket ID #EPA-R08-OAR-2015-0709),
adoption of the VOC control measures required under this FIP may
result in very small NO<INF>X</INF> emission increases. We estimate
that these additional NO<INF>X</INF> emissions would be at most 27
tpy total. Considering the large amount of VOC emission reductions
that the same controls will achieve, the small potential
NO<INF>X</INF> emissions increase will not counteract the effect of
the VOC reductions or adversely affect the area's ability to attain
the NAAQS.
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We had previously informed the public of our intent to undertake
action specific to the Indian country lands within the U&O Reservation;
as noted earlier, in the preamble to the National O&NG FIP, we stated:
``For the Uintah and Ouray Reservation, we have sufficient concerns
about the air quality impacts from existing sources that we plan to
propose a separate U&O FIP.'' \64\ After further review, and
considering the emissions information presented below, the EPA
concludes that those concerns are still warranted, and that this action
is necessary and appropriate to address poor air quality on the Indian
country lands within the U&O Reservation.
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\64\ See 81 FR at 35963 (June 3, 2016).
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E. Emissions Information
In 2020, the EPA, in cooperation with the UDEQ and the Ute Indian
Tribe, developed the UBEI2017-Update, an emission inventory of oil and
natural gas activity in the Uinta Basin that was populated with data
provided by oil and natural gas operators in the Basin.\65\ We are also
aware of several other available sources of information on air
emissions from oil and natural gas activity in the Uinta Basin,
including: (1) the 2017 National Emissions Inventory (2017 NEI); \66\
(2) a study by the Western Regional Air Partnership (WRAP); \67\ (3)
existing true minor source registration data and new and modified true
minor source registration submitted to the EPA under the Federal Indian
Country Minor NSR Program; \68\ and (4) EPA Greenhouse Gas Reporting
Program, subpart W Petroleum and Natural Gas Systems.\69\ They are
discussed in more detail in the Regulatory Impact Analysis (RIA) for
this final rule.\70\
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\65\ The inventory and supporting analysis can be viewed in the
docket for this rule, in the Microsoft Excel spreadsheet titled,
``UO FIP cost and emissions analysis.xlsx'' (Docket ID No. EPA-R08-
OAR-2015-0709). This U&O FIP requires owners and operators to submit
triennial emissions inventories, similar to a requirement finalized
by the UDEQ in March of 2018. These triennial updates will provide
information on how emissions are changing in the Basin from the 2017
baseline. See Section V (Summary of FIP Provisions).
\66\ See 2017 National Emissions Inventory (2017 NEI), available
at <a href="https://www.epa.gov/air-emissions-inventories/2017-national-emissions-inventory-nei-data">https://www.epa.gov/air-emissions-inventories/2017-national-emissions-inventory-nei-data</a>, accessed Sept. 28, 2020. Queried:
Duchesne & Uintah Counties VOC-NOx all sectors; Ute Indian Tribe of
the Uintah & Ouray Indian Reservation VOC-NOx all sectors. EPA's
analysis of the 2017 NEI data is available in the docket for this
rulemaking (Docket ID No. EPA-R08-OAR-2015-0709), Microsoft Excel
spreadsheet titled ``2017 NEI Uinta Basin_Duchesne Counties_U&O_VOC-
NOx.xlsx. The UDEQ submitted the UBEI2017 to the 2017 NEI, but later
updated it for storage vessel, pneumatic controller, pneumatic pump,
fugitive, gas well liquid unloading, blowdowns and pigging and
oilfield wastewater emissions that are planned to be submitted to
the NEI at a future date (see footnote 75). Analysis of the 2017 NEI
for the purposes of this final U&O FIP was prepared using the
version publicly available before incorporating these updates from
the UDEQ.
\67\ Western Regional Air Partnership (WRAP), O&G Emissions
Workgroup: Phase III Inventory, Uinta Basin Reports, 2012 Mid-Term
Projection Technical Memo, ``Development of 2012 Oil and Gas
Emissions Projections for the Uinta Basin'', March 25, 2009,
available at <a href="http://www.wrapair2.org/PhaseIII.aspx">http://www.wrapair2.org/PhaseIII.aspx</a>, accessed Mar.
14, 2022. Some of the 2014 Uinta Basin Emissions Inventory was
generated from prorating the 2012 WRAP estimates (which prorated and
adjusted their 2006 work) to 2014 activity levels.
\68\ Data from existing true minor source registration reports
and data from new and modified true minor oil and natural gas source
registrations under the National O&NG FIP, submitted under 40 CFR
49.160 of the Federal Indian Country Minor NSR Program by operators
of sources on the Indian country lands within the U&O Reservation.
\69\ EPA Greenhouse Gas Reporting Program (GHGRP) Petroleum and
Natural Gas Systems, available at <a href="https://www.epa.gov/ghgreporting/ghgrp-petroleum-and-natural-gas-systems">https://www.epa.gov/ghgreporting/ghgrp-petroleum-and-natural-gas-systems</a>, accessed Mar. 14, 2022.
\70\ The RIA can be viewed in the docket for this rulemaking
(Docket ID No. EPA-R08-OAR-2015-0709).
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The 2017 NEI provides a general picture of the relative
contributions of ozone-forming emissions from the oil and natural gas
sector as compared to other industry sectors, estimating that emissions
from the production segment of the oil and natural gas sector were the
largest anthropogenic \71\ contributor of both VOC and NO<INF>X</INF>
emissions in the Uinta Basin, at 97 percent of the VOC emissions and 64
percent of the NO<INF>X</INF> emissions. The WRAP study provides a
general picture of the relative emissions contribution in the Basin
from various oil and natural gas equipment and activities on Indian
country lands. The existing minor source registration data provide a
general picture of the large percentage of unpermitted and likely
uncontrolled minor emissions sources on Indian country lands within the
U&O Reservation. EPA Greenhouse Gas Reporting Program, subpart W,
provides annual reports by operators of activity levels and methane
emissions from oil and natural gas operations in the Uinta Basin. The
UBEI2017-Update is a comprehensive source of oil and natural gas source
VOC emissions data for the Uinta Basin that provided information for
the cost and benefit analysis supporting this rulemaking.
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\71\ The calculation excludes biogenic sources of VOC and
NO<INF>X</INF>, because elevated ozone occurs during the winter when
vegetation and soils are presumed to not be a contributor because
they are dormant or covered by snow.
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The UBEI2017-Update indicates that the majority of existing oil and
natural gas sources in the region are on Indian country lands within
the U&O Reservation. As explained in more detail below, most of these
are minor sources and are uncontrolled. The 2017 NEI indicates that,
compared to other industry sector sources, existing oil and natural gas
sources are cumulatively the largest anthropogenic contributor of VOC
(97 percent) and NO<INF>X</INF> (64 percent) to measured exceedances of
the ozone NAAQS in the Uinta Basin. Existing oil and natural gas
sources on the portions of the Basin regulated by the UDEQ are subject
to emission reduction requirements, while existing sources on Indian
country lands within the U&O Reservation were previously either subject
to less stringent regulation or no regulation at all.
[[Page 75345]]
Specifically, the UBEI2017-Update shows that 76 percent of all
existing oil and natural gas facilities (including well sites
processing fluids from multiple individual wells, as well as compressor
stations and other processing facilities) in the Uinta Basin are
located on Indian country lands within the U&O Reservation. According
to the inventory, almost 73,000 tons of VOC and over 6,700 tons of
NO<INF>X</INF> emissions were emitted in 2017 from existing oil and
natural gas sources on Indian country lands within the U&O Reservation.
That is approximately 89 percent of the total oil and natural gas-
related VOC emissions in the Uinta Basin and approximately 63 percent
of the total oil and natural gas-related NO<INF>X</INF> emissions in
the Uinta Basin. These data confirm that the bulk of the ozone-related
emissions in the Uinta Basin are released from sources on the Indian
country lands within the U&O Reservation.
Many of the oil and natural gas sources on Indian country lands
within the U&O Reservation are uncontrolled. According to the UEBI2017-
Update, on the Indian country lands within the U&O Reservation, 85
percent of the total number of existing storage vessels, 98 percent of
the total number of existing glycol dehydrators and 99 percent of
existing pneumatic pumps are uncontrolled emitters of VOC. By contrast,
in areas of the Basin where the EPA has approved the UDEQ to implement
the CAA, 68 percent of the total number of existing storage vessels and
52 percent of the total number of existing glycol dehydrators are
uncontrolled (uncontrolled pneumatic pump numbers are relatively
equivalent to Indian country at 99 percent). The UDEQ has adopted
revisions to existing oil and natural gas source requirements and
existing minor source permitting requirements, and has adopted new
requirements, including a Permit by Rule that replaces the requirement
for minor oil and natural gas sources to obtain a site-specific
permit.\72\ Now that the revised and new requirements are effective, we
expect the percentage of uncontrolled existing storage vessels and
glycol dehydrators in areas of the Basin where the EPA has approved the
UDEQ to implement the CAA will decrease from what was reported in the
UBEI2017-Update. The UDEQ's rule revisions and new rules are discussed
in more detail in the preamble to the proposed FIP.\73\ In addition,
the UBEI2017-Update shows that emissions from oil and natural gas
wastewater disposal facilities on the Indian country lands within the
U&O Reservation comprise approximately 35 percent of the total VOC
emissions from oil and natural gas activity on the Indian country lands
within the U&O Reservation. As explained in the preamble to the
proposed FIP,\74\ these facilities may not be controlled under the CAA,
because they do not meet the applicability criteria of preconstruction
permitting programs or federal emissions standards regulating them.
---------------------------------------------------------------------------
\72\ Utah State Bulletin, Official Notices of Utah State
Government, Filed Jan. 3, 2018, 12:00 a.m. through Jan. 16, 2018,
11:59 p.m., 11:59 p.m., Number 2018-3, February 01, 2018, Nancy L.
Lancaster, Managing Editor, pages 46-68, available in the docket for
this rulemaking (Docket ID No. EPA-R08-OAR-2015-0709.
\73\ See 85 FR 3504-3506, Section IV. D. Developing the Proposed
Control Requirements, 3. Evaluation of State Oil and Natural Gas and
Permitting-Related Requirements.
\74\ See 85 FR 3503-3504, Section IV. D. Developing the Proposed
Control Requirements, 2. Evaluation of Federal Oil and Natural Gas
and Permitting-Related Requirements.
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Based on this collection of emissions information (and other
information about meteorological conditions and local geography), the
EPA has concluded that winter ozone levels in the Uinta Basin are most
significantly influenced by VOC emissions from the presence of numerous
minor, unpermitted and largely uncontrolled oil and natural gas
production operations on Indian country lands within the U&O
Reservation.
F. What is a FIP?
Under section 302(y) of the CAA, the term ``Federal implementation
plan'' means ``a plan (or portion thereof) promulgated by the
Administrator to fill all or a portion of a gap or otherwise correct
all or a portion of an inadequacy in a state implementation plan, and
which includes enforceable emission limitations or other control
measures, means or techniques (including economic incentives, such as
marketable permits or auctions of emissions allowances), and provides
for attainment of the relevant national ambient air quality standard.''
As discussed previously in section III.B., CAA sections 301(a) and
301(d)(4) and 40 CFR 49.11(a) authorize the EPA to promulgate such FIPs
as are necessary or appropriate to protect air quality if a Tribe does
not submit or receive EPA approval of a TIP.
The Federal Indian Country Minor NSR rule is an example of a FIP,
as discussed in section III.C. Another example of the EPA's use of its
FIP authority to protect air quality in areas of Indian country with no
EPA-approved program, while at the same time seeking to provide a
consistent regulatory environment where appropriate, is the ``FIP for
Oil and Natural Gas Well Production Facilities; Fort Berthold Indian
Reservation (FBIR; Mandan, Hidatsa, and Arikara Nation), North
Dakota.'' \75\ In that rule, we took an important initial step to
control VOC emissions from existing, new, and modified oil and natural
gas operations on the FBIR. We drafted requirements that were
consistent to the greatest extent practicable with the most relevant
aspects of neighboring state and local rules concerning the air
pollutant emitting activities on the FBIR. We did not intend at the
time, nor did we expect, the regulation to impose significantly
different regulatory burdens upon industry or the residents of the FBIR
than those imposed by the rules of state and local air agencies in the
surrounding areas.
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\75\ See 78 FR 17836 (Mar. 22, 2013).
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This U&O FIP specific to Indian country lands within the U&O
Reservation will reduce VOC emissions related to the formation of
ozone. Exceedances of both the 2008 and the 2015 ozone NAAQS have
occurred at air quality monitors on and around the Reservation, and
portions of the Uinta Basin, including portions of the U&O Reservation,
were designated by the EPA in 2018 as nonattainment for the 2015 ozone
NAAQS. There are no currently approved TIPs that apply to existing oil
and natural gas sources on Indian country lands within the U&O
Reservation. Finally, the majority of the sources covered by this U&O
FIP have not previously been subject to federally required emissions
controls, as discussed further in Section IV.A of the preamble to the
proposed FIP.\76\ For all of these reasons, we have concluded that is
both necessary and appropriate to protect air quality on the Indian
country lands within the U&O Reservation by promulgating this FIP.
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\76\ See 85 FR 3501, Section IV. Developing the Proposed Control
Rule, A. Rationale for the Proposed Rule.
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G. Oil and Natural Gas Industry in the Uinta Basin
The oil and natural gas industry in the Uinta Basin includes the
extraction and production of oil and natural gas, as well as the
processing, transmission, and distribution of natural gas.
Specifically, for oil, the industry in the Uinta Basin includes all
operations from the well to transfer to an oil transmission pipeline or
other means of transportation to a petroleum refinery. The petroleum
refinery is not considered part of the oil and natural gas industry.
Thus, with respect to
[[Page 75346]]
crude oil, the oil and natural gas industry ends where crude oil enters
an oil transmission pipeline or other means of transportation to a
petroleum refinery. For natural gas, the industry includes all
operations from the well to the final end user.
The oil and natural gas industry in the Uinta Basin can generally
be separated into four segments: (1) oil and natural gas production;
(2) natural gas processing; (3) natural gas transmission and storage;
and (4) natural gas distribution. This U&O FIP for oil and natural gas
sources on Indian country lands within the U&O Reservation focuses on
existing, new, and modified sources in the first and second segments,
oil and natural gas production and natural gas processing, because the
existing minor sources in those segments cumulatively contribute the
largest portion of VOC emissions from the oil and natural gas industry
on the Indian country portion of the U&O Reservation. There are more
than 6,870 individual oil and natural gas sources (operated by 33
distinct entities) on the Indian country lands within the U&O
Reservation, the majority of which are well sites in the oil and
natural gas production segment.\77\ As discussed earlier, the 2017 NEI
shows that emissions from the production segment of the oil and natural
gas sector were estimated to be the largest anthropogenic contributor
of both VOC and NO<INF>X</INF> emissions in the Uinta Basin.
Comparatively, the categories that include oil and natural gas storage
and transfer and bulk gasoline terminals (segments 3 and 4), are
reported in the 2017 NEI as contributing less than one percent each of
the total VOC and NO<INF>X</INF> emissions in the Uinta Basin.\78\ Of
the 13,363 individual active oil and natural gas wells in the Uinta
Basin, over 10,108 wells, or about 76 percent, are on Indian country
lands within the U&O Reservation.
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\77\ 2017 Uinta Basin Oil and Natural Gas Emissions Inventory
Update (UBEI2017-Update). The inventory and supporting analysis can
be viewed in the docket for this rulemaking. See ``UO FIP cost and
emissions analysis.xlsx'' (Docket ID No. EPA-R08-OAR-2015-0709).
\78\ Based on the NEI Source Type to Sector Crosswalk in the
2017 NEI, available at <a href="https://www.epa.gov/air-emissions-inventories/2017-national-emissions-inventory-nei-data">https://www.epa.gov/air-emissions-inventories/2017-national-emissions-inventory-nei-data</a>, accessed
Mar. 14, 2022. Queried: Duchesne & Uintah Counties VOC-NOx all
sectors; Ute Indian Tribe of the Uintah & Ouray Indian Reservation
VOC-NOx all sectors. The EPA's analysis of the 2017 NEI data is
available in the docket for this rulemaking (Docket ID No. EPA-R08-
OAR-2015-0709), Microsoft Excel spreadsheet titled ``2017 NEI Uinta
Basin_Dechesne Counties_U&O_VOC-NOx.xlsx.''
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The oil and natural gas production segment in the Uinta Basin
includes wells and all related processes used in the extraction,
production, recovery, lifting, stabilization, and separation or
treatment of oil and/or natural gas (including condensate). Production
components in the Uinta Basin may include wells and related casing
head, tubing head, and ``Christmas tree'' piping, as well as pumps,
compressors, heater treaters, separators, storage vessels, pneumatic
devices, pneumatic pumps, and natural gas dehydrators. Production
operations in the Uinta Basin also include the well drilling,
completion, and workover processes, and include all the portable non-
self-propelled apparatuses associated with those operations. Production
sites in the Uinta Basin include not only the sites where the wells
themselves are located, but also centralized gas and liquid gathering
sources where oil, condensate, produced water, and natural gas from
several wells may be separated, stored, and treated. Production
components in the Uinta Basin also include the smaller diameter, low-
to-medium-pressure gathering pipelines and related components that
collect and transport the oil, natural gas, and other materials and
wastes from the wells or well pads.
The natural gas production segment in the Uinta Basin ends where
the natural gas enters a natural gas processing plant. Where there is
no processing plant, the natural gas production segment ends at the
point where the natural gas enters the transmission segment for long-
line transport. The crude oil production segment in the Uinta Basin
ends at the storage and load-out terminal, which is the point of
custody transfer to an oil pipeline or for transport of the crude oil
to a petroleum refinery via trucks or railcars.
Each producing crude oil and natural gas field has its own unique
properties. The composition of the crude oil and the natural gas as
well as the reservoir characteristics are likely to be different across
all reservoirs. The RIA for this rule provides a more detailed overview
of the products and components of the oil and natural gas industry that
are relevant to the activities in the Uinta Basin.\79\
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\79\ The RIA for the final rule can be viewed in the docket for
this rulemaking (Docket ID No. EPA-R08-OAR-2015-0709).
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IV. Summary of the Final U&O FIP
A. Overview
The emissions control and other requirements of this final FIP that
will reduce VOC emissions from existing, new, and modified oil and
natural gas sources on Indian country lands within the U&O Reservation
are summarized in this section. Significant changes since proposal are
discussed in more detail in section V of this preamble. The FIP
includes emissions control efficiency requirements and operational and
work practice standards, each with associated monitoring, testing,
recordkeeping, and reporting requirements, as appropriate. Oil and
natural gas sources must comply with these requirements, except as
specifically exempted under the FIP for certain equipment or activities
otherwise subject to existing federal standards 40 CFR part 60,
subparts OOOO or OOOOa, or 40 CFR part 63, subpart HH. Also discussed
in this section are the features of the FIP that are necessary to
facilitate its implementation.
This final rule applies to owners or operators of oil and natural
gas sources that either produce oil and natural gas or process natural
gas, that are located on Indian country lands within the U&O
Reservation, and that meet the applicability criteria specified for
each set of requirements. It includes the following provisions in 40
CFR part 49:
49.4169 Introduction.
49.4170 Delegation of authority of administration to the Tribe.
49.4171 General provisions.
49.4172 Emissions Inventory.
49.4173 VOC emissions control requirements for storage vessels.
49.4174 VOC emissions control requirements for dehydrators.
49.4175 VOC emissions control requirements for pneumatic pumps.
49.4176 VOC emissions control requirements for covers and closed-vent
systems.
49.4177 VOC emissions control devices.
49.4178 VOC emissions control requirements for fugitive emissions.
49.4179 VOC emissions control requirements for tank truck loading.
49.4180 VOC emissions control requirements for pneumatic controllers.
49.4181 Other combustion devices.
49.4182 Monitoring and testing requirements.
49.4183 Recordkeeping requirements.
49.4184 Notification and reporting requirements.
We do not expect a substantial number of the existing oil and
natural gas sources subject to this U&O FIP to also be subject to NSPS
OOOO or OOOOa, or NESHAP HH, for the specific equipment and activities
regulated. However, to minimize regulatory burdens where such a
potential overlap does exist, this rule finalizes the proposed
provisions that equipment or activities that are affected
[[Page 75347]]
by any requirement in this U&O FIP and that are also subject to the
substantive emissions control requirements in those EPA standards will
not be subject to this FIP's substantive emissions control requirements
for such equipment and activities. As an example, given the exemptions
being finalized, if an existing, new, or modified oil and natural gas
source on Indian country lands within the U&O Reservation has storage
vessels, pneumatic pumps, and fugitive emissions components that are
subject to the emissions control requirements of NSPS OOOOa, then that
source would be subject to the substantive emissions control
requirements for glycol dehydrators in the FIP, but not to the FIP's
substantive emissions control requirements for storage vessels,
pneumatic pumps, or fugitive emissions components.
B. Introduction
In 40 CFR 49.4169 (Introduction) we are finalizing our proposal to
specify: (1) the purpose of this U&O FIP; (2) the general applicability
of this U&O FIP; and (3) the compliance schedule for this U&O FIP.
We are finalizing text that: (1) establishes provisions for
delegation of authority to allow the Ute Indian Tribe to assist the EPA
with administration of this U&O FIP in 40 CFR 49.4170; (2) establishes
general provisions and definitions applicable to oil and natural gas
sources in 40 CFR 49.4171; (3) establishes a requirement for oil and
natural gas sources to submit emissions inventories on a triennial
basis, beginning with an inventory for calendar year 2023 in 40 CFR
49.4172; and (4) establishes, in 40 CFR 49.4173 through 49.4184,
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 on Indian country lands within the U&O Reservation.
This final rule provides that compliance with the rule for oil and
natural gas sources that commence construction on or after the
effective date of the final rule is required upon startup. Compliance
for sources existing as of the effective date of the final rule is
required no later than 12 months after the effective date of the final
rule. We concluded that it is important to allow owners/operators of
existing sources a reasonable period of time to conduct any necessary
retrofit-related activities, such as (1) acquiring control devices, (2)
conducting manufacturer-recommended testing to be compliant with the
requirements, and (3) securing the necessary trained personnel to
install compliant devices and associated piping and instrumentation. We
expect that there will be about 2,165 existing oil and natural gas
sources that may require equipment retrofit and installation of VOC
emission control equipment (combustion controls) under the final rule.
Additionally, we estimate that more than 700 high-bleed pneumatic
controllers will need to be retrofitted to low-or no-bleed. We have
determined that providing 12 months from the effective date of the
final rule to install retrofits at existing sources is a reasonable
amount of time for efficient, cost-effective project planning that
accounts for a level, sustained equipment and labor resource demand
that can be supported by the vendor community, while ensuring that
meaningful emissions reductions will be achieved that provide near-term
benefits to improve air quality and make progress toward future
attainment.\80\
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\80\ 12 months is a tighter compliance timeframe than is
required for existing sources in NESHAP regulations, which is
typically 3 years. The purpose of this proposed U&O FIP, though, is
to address air quality in a timely fashion. Moreover, the final rule
allows sources to request extensions of the compliance date beyond
the 12 months if needed.
---------------------------------------------------------------------------
We are also finalizing a provision to allow an owner or operator on
a case-specific basis to submit a written request to the EPA for an
extension of the compliance deadline for existing sources, which must
include appropriate justification of the reason for the request. Any
approval or denial of an extension request, including the length of any
approved extension, will be based on the merits of each case. Factors
that the EPA will consider in deciding whether to grant an extension
request under the provision include the economic and technical
feasibility of meeting this U&O FIP's control requirements in the
prescribed timeframe. The final FIP specifies the criteria that the EPA
will apply in responding to requests for extension of the compliance
period, including that the request must be submitted before the
compliance deadline, must identify the specific provisions for which an
extension is being requested and include an alternative compliance
deadline, and must provide a rationale for the request with supporting
information explaining how the operator will effectively meet all
applicable requirements after the requested alternative compliance
deadline.
C. Provisions for Delegation of Administration to the Ute Indian Tribe
We are establishing in 40 CFR 49.4170 (Delegation of authority of
administration to the Tribe) the steps by which the Ute Indian Tribe
may request delegation to assist us with the administration of this
rule, and the process by which the Regional Administrator of EPA Region
8 may delegate to the Ute Indian Tribe the authority to assist with
such administration. As described in the regulatory provisions, any
such delegation will be accomplished through a delegation of authority
agreement between the Regional Administrator and the Tribe. This
section provides for administrative delegation of this federal rule and
does not affect the TAS eligibility criteria under CAA section 301(d)
and 40 CFR 49.6 should the Ute Indian Tribe decide to seek such
treatment for the purpose of administering its own EPA-approved TIP
under tribal law. Administrative delegation is a separate process from
TAS under the TAR. Under the TAR, Indian tribes seek the EPA's approval
of their eligibility to implement CAA programs under their own laws.
The Ute Indian Tribe will not need to seek TAS under the TAR for
purposes of requesting to assist us with administration of this rule
through a delegation of authority agreement. If delegation does occur,
the rule would continue to operate under federal authority on Indian
country lands within the U&O Reservation, and the Ute Indian Tribe
would assist us with administration of the rule to the extent specified
in the agreement.
D. General Provisions
We are finalizing in 40 CFR 49.4171 (General provisions): (1) a
requirement to design, operate, and maintain all equipment used for
hydrocarbon liquid and gas collection, storage, processing, and
handling operations covered under this rule, in a manner consistent
with good air pollution control practices and that minimizes leakage of
VOC emissions to the atmosphere. Determination of whether acceptable
operating and maintenance procedures are being used will be based on
information available to the EPA, including monitoring results, review
of operating and maintenance procedures, and inspection of the source;
and (2) definitions.
E. Emissions Inventory Requirements
We are finalizing in 40 CFR 49.4172 a requirement for owners/
operators of oil and natural gas sources with the
[[Page 75348]]
potential to emit one or more NSR-regulated pollutants at levels
greater than one tpy to submit an annual emissions inventory, once
every three years beginning with calendar year 2024, that covers
emissions from the previous calendar year (2023 for the first required
inventory). Each triennial inventory must be submitted no later than
April 15th of the year after each inventory year. The triennial
emissions inventory requirement will suffice for the purpose of
continued updates to the comprehensive Uinta Basin oil and natural gas
emissions inventory by the UDEQ, the Ute Indian Tribe, and the EPA.
Owners/operators must submit actual emissions for each emissions unit
at each oil and natural gas source covered by the requirement in a
standard format specified by the Regional Office and available on our
website. The format will be consistent with the format used by the UDEQ
to collect information from sources in the Uinta Basin outside of
Indian country lands within the U&O Reservation.
F. VOC Emissions Control Requirements
The discussion in this section details the final VOC emissions
control requirements of this FIP and how they compare to existing state
and federal requirements for the equipment and activities listed in
Table 3. The most notable difference between the final VOC emissions
control requirements of this FIP and the Utah Oil and Gas Rules \81\
and Utah Permit Requirements \82\ is that the Utah permit by rule's 4
tpy total VOC emissions threshold for requiring controls does not
include pneumatic pump emissions. We have determined that emissions
from pneumatic pumps are a large source of VOC emissions on the Indian
country lands within the U&O Reservation, but a negligible source of
VOC emissions in the areas in the Basin where the EPA has approved the
UDEQ to implement the CAA. This difference in the share of pneumatic
pumps emissions in the inventory is because the majority of natural gas
production operations, which use gas-driven pneumatic pumps, occurs on
the Reservation, while lands where air quality is managed by the UDEQ
feature mostly oil production. This difference is explained in more
detail later in this section.
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\81\ Utah Administrative Code Chapter R307-500 Series (Oil and
Gas), available in the docket for this rulemaking (Docket ID No.
EPA-R08-OAR-2015-0709). These rules, referred to collectively as the
``Utah permit by rule,'' are state-only rules and the UDEQ has not
submitted them to the EPA for approval in the Utah SIP.
\82\ Utah Administrative Code Chapter R307-401 (Permits: New and
Modified Sources), available in the docket for this rulemaking
(Docket ID No. EPA-R08-OAR-2015-0709); See 40 CFR part 52, subpart
TT.
\83\ The National O&NG FIP incorporates the requirements of the
eight standards, as they apply to a source. To make emissions
control requirements across the Basin consistent, this U&O FIP goes
beyond the eight federal standards to regulate certain equipment and
activities that are not regulated by established EPA standards (or
are regulated differently) but are regulated in UDEQ standards. In
addition, the EPA issued subsequent rules that revised certain
provisions of NSPS OOOO and OOOOa (The 2020 Policy Rule and 2020
Technical Rule; see discussion above in Section I.B.). The 2021 CRA
resolution disapproved the policy amendments of NSPS OOOO and OOOOa.
PL 17-23 (June 30, 2021). The requirements summarized in this table
reflect the standards that are in effect today--the methane
standards in the 2016 NSPS OOOOa and the 2016 VOC standards in NSPS
OOOO and OOOOa, as they were amended in 2020. The EPA's Oil and
Natural Gas Sector Climate Review Proposed Rule would revise
existing VOC standards under NSPS OOOO and OOOOa, establish new
methane and VOC standards for new and modified emissions sources not
previously covered by NSPS OOOO and OOOOa, and establish emissions
guidelines for existing sources. This table does not reflect those
proposed standards and guidelines. We may revisit this final action
in the future based on any final action we take under CAA section
111 with the Oil and Natural Gas Sector Climate Review rulemaking.
Table 3--U&O FIP VOC Emissions Control Requirements for Existing, New, and Modified Oil and Natural Gas Sources Versus UDEQ and Other Federal \83\
Control Requirements
--------------------------------------------------------------------------------------------------------------------------------------------------------
U&O FIP VOC Emissions Controls Utah oil and gas
------------------------------------------------------------------------- rules and Utah
Final FIP requirements (section Applicability Control efficiency permit NSPS OOOO NSPS OOOOa NESHAP HH
in 40 CFR part 49) threshold (percent) requirements
--------------------------------------------------------------------------------------------------------------------------------------------------------
Storage vessel VOC emission Source-wide Reduce VOC by 95.0 Issued Utah Permit Reduce VOC by 95.0 Reduce VOC by 95.0 Reduce HAP by 95.0
control requirements (Sec. potential for VOC percent or route Requirements percent or route percent or route percent or route
49.4173). emissions from to a process. (BACT for site- to a process for to a process for to a process for
the collection of See also VOC specific & individual individual individual
all storage emission control general approval storage vessels storage vessels storage vessels
vessels, devices later in orders)--Reduce with potential with potential with potential
dehydrators and this table (Sec. VOC by 98 percent for >=6 tpy per for >=6 tpy per for flash
pneumatic pumps 49.4177). or route to a storage vessel storage vessel emissions and
>=4 tpy. process where constructed, constructed, actual annual
source-wide reconstructed or reconstructed or average
uncontrolled modified after modified after hydrocarbon
actual VOC August 23, 2011, September 18, liquid throughput
emissions from and on or before 2015 >=79,500 liters/
the collection of September 18, (alternatively, day.
all storage 2015 no control
vessels, (alternatively, required if
dehydrators and no control uncontrolled
pneumatic pumps required if actual VOC
>=4 tpy. uncontrolled emissions
Utah Oil and Gas actual VOC maintained <4tpy).
Rules--Reduce VOC emissions
by 95 percent or maintained <4
route to a tpy).
process if total
uncontrolled
actual emissions
from the
collection of
dehydrators and
storage vessels
>=4 tpy VOC (does
not include
pneumatic pump
emissions), or if
source with
storage vessels
only has through
put >=8,000 bbl
crude oil or
2,000 bbl
condensate, on
rolling 12-month
basis--unless <=4
tpy source-wide
uncontrolled
actual emissions
of VOC from the
collection of all
storage vessels.
[[Page 75349]]
Dehydrators VOC emission control See VOC emission Issued Utah Permit Not covered....... Not covered....... For units at major
requirements (Sec. 49.4174). control devices Requirements HAP sources and
later in this (BACT for site- non-urban area
table (Sec. specific & sources with
49.4177). general approval actual annual
orders)--Reduce average flowrate
VOC by 98 percent of natural gas
or route to a >=85,000 standard
process where m3/day, reduce
source-wide HAP by 95.0
uncontrolled percent or route
actual VOC to a process.
emissions from Units with actual
the collection of annual average
all storage flowrate of
vessels, natural gas
dehydrators and <85,000 standard
pneumatic pumps m3/day not
>=4 tpy. covered--this is
Utah Oil and Gas the majority of
Rules--Reduce VOC units on Indian
by 95 percent if country lands
total within the U&O
uncontrolled Reservation.
actual emissions
from the
collection of
dehydrators and
storage vessels
>=4 tpy VOC (does
not include
pneumatic pump
emissions).
Pneumatic pumps VOC emission See VOC emission Issued Utah Permit Not covered....... Reduce VOC by 95.0 Not covered.
control requirements (Sec. control devices Requirements percent (if
49.4175). later in this (BACT for site- control device is
table (Sec. specific & already on site)
49.4177). general approval or route to a
orders)--Reduce process (if
VOC by 98 percent technically
or route to a feasible) for
process where natural gas-
source-wide driven diaphragm
uncontrolled pneumatic pumps
actual VOC at well sites
emissions from constructed,
the collection of reconstructed or
storage vessels, modified after
dehydrators and September 18,
pneumatic pumps 2015.
>=4 tpy. Zero natural gas
Utah Oil and Gas emissions for
Rules does not natural gas
require control processing plants
of pneumatic pump constructed after
emissions. September 18,
2015.
Covers and closed-vent system Source-wide 100 percent of VOC 100 percent of 100 percent of 100 percent of 100 percent of HAP
VOC emission control potential for VOC emissions routed storage vessel, storage vessel storage vessel emissions, if
requirements (Sec. 49.4176). emissions from to process or dehydrator and VOC emissions emissions routed required to
the collection of control device. pneumatic pump routed to control to control device control glycol
all storage emissions routed device or process. or process. dehydrators and/
vessels, to control device or storage
dehydrators and or process in vessels.
pneumatic pumps issued Utah
>=4 tpy. Permit
Requirements and
Rules (BACT for
site-specific &
general approval
orders).
Utah Oil and Gas
Rules--100
percent storage
vessel and
dehydrator
emissions routed
to control device
or process (Utah
Oil and Gas Rules
do not include
routing pneumatic
pump emissions).
VOC emission control devices Source-wide 95.0 percent 98.0 percent 95.0 percent 95.0 percent If required to
(Sec. 49.4177). potential for VOC continuously. continuous VOC continuous VOC continuous VOC control glycol
emissions from control control control dehydrator or
the collection of efficiency for efficiency. efficiency. storage vessel
all storage Issued Utah HAP emissions,
vessels, Permit must reduce HAP
dehydrators and Requirements by 95.0 percent,
pneumatic pumps (BACT for site- or maintain <20
>=4 tpy. specific & parts per million
general approval volume (ppmv) or
orders). 1 tpy benzene.
95 percent
continuous
control
efficiency for
Utah Oil and Gas
Rules.
[[Page 75350]]
Fugitive emissions VOC emission Source-wide NA-Semi-annual Utah Oil and Gas For natural gas For well sites and Ensure closed-vent
control requirements (Sec. potential for VOC surveys. Rules--semi- processing plants compressor system operates
49.4178). emissions from annual surveys at constructed, stations with no
the collection of all registered reconstructed, or constructed, detectable
all storage well sites modified after reconstructed or emissions if
vessels, required to August 23, 2011, modified after required to
dehydrators and control storage and on or before September 18, control glycol
pneumatic pumps vessel and/or September 18, 2015--Fugitive dehydrator or
>=4 tpy. dehydrator VOC 2015--LDAR emissions surveys storage vessel
Or................ emissions. requirements as using OGI HAP emissions.
Well site Issued Utah Permit referenced in conducted
production >15 Requirements NSPS VVa, with semiannually
boe per day (sources exempt periodic EPA (well sites) and
(rolling from Utah Oil and Method 21 surveys quarterly
consecutive 12- Gas Rules) on specific (compressor
month average). require LDAR, equipment types. stations).
ranging from For natural gas
annual to processing plants
quarterly for all constructed,
approved (i.e., reconstructed or
permitted) oil modified after
and natural gas September 18,
sources, 2015--LDAR
including requirements as
compressor referenced in
stations. NSPS VVa, with
periodic EPA
Method 21 surveys
on specific
equipment types.
Tank truck loading VOC emission None--applies to NA--Bottom filling Utah Oil and Gas Not covered....... Not covered....... Not covered.
control requirements (Sec. all existing or submerged fill Rules--more
49.4179). sources. pipe. stringent, as
capture and
control of VOC
emissions (95
percent
efficiency)
required at
registered
sources required
to control
storage vessel
and glycol
dehydrator
emissions.
Pneumatic controllers VOC NA--meet the Utah Oil and Gas For continuous For continuous Not covered.
emission control requirements standards of NSPS Rules--Meet bleed natural gas bleed natural gas
(Sec. 49.4180). OOOO or OOOOa. standards of NSPS driven pneumatic driven pneumatic
OOOO. controllers controllers
constructed, constructed,
reconstructed or reconstructed or
modified after modified after
October 15, 2013 September 18,
and on or before 2015, zero-bleed
September 18, for processing
2015, zero-bleed plants and low-
for processing bleed (<6 scfh)
plants and low- elsewhere.
bleed (<6 scfh)
elsewhere.
Other combustion devices (Sec. NA--must be Utah Oil and Gas Not covered....... Not covered....... Not covered.
49.4181). equipped with Rules--must be
automatic equipped with
ignition device. automatic
ignition device.
--------------------------------------------------------------------------------------------------------------------------------------------------------
1. Storage Vessels, Glycol Dehydrators, and Pneumatic Pumps
For existing, new, and modified sources, we are finalizing in 40
CFR 49.4173 (Storage vessel VOC emission control requirements), 40 CFR
49.4174 (Dehydrators VOC emission control requirements), and 40 CFR
49.4175 (Pneumatic pumps VOC emission control requirements) the
requirement that owners and operators of affected storage vessels,
glycol dehydrators, and natural gas-driven pneumatic pumps either: (1)
reduce VOC emissions from flashing, working, standing, and breathing
losses from the collection of all crude oil, condensate, intermediate
hydrocarbon and produced water storage vessels, glycol dehydrator
process vents (glycol dehydrator regenerator or still vent and the vent
from the dehydrator flash tank, if present), and pneumatic pumps, by at
least 95.0 percent on a continuous basis; or (2) maintain the source-
wide uncontrolled actual VOC emissions from the collection of all
storage vessels, glycol dehydrators, and pneumatic pumps at a rate of
less than 4 tpy. We are finalizing the requirement that applicability
for the VOC emissions control requirements be determined specifically
according to the following criteria. For oil and natural gas sources
that began operation before the effective date of the final rule, we
are requiring that applicability be determined using potential for VOC
emissions. Potential for VOC emissions must be calculated using a
generally accepted model or calculation methodology based on the
maximum average daily throughput, as determined for existing sources
using the highest 30-day period of production in the 12 consecutive
months before the compliance deadline of the rule for each affected
source. The determination may take into account requirements under
legally and practicably enforceable limits in an applicable operating
permit or other applicable federal requirement, such as those in NSPS
OOOO or OOOOa, or NESHAP HH. For oil and natural gas sources that begin
operation or modification after the effective date of the final rule,
we are requiring that applicability for glycol dehydrators and
pneumatic pumps be determined using potential to emit VOC, and that
emissions from the collection of all storage vessels be controlled upon
startup for a minimum of 12 consecutive months. This requirement for
new and modified storage vessels is being finalized because of the
uncertainty of well production levels before operation begins. After a
minimum of 12 consecutive months of operation, controls may be removed
if source-wide uncontrolled actual VOC emissions from the collection of
all storage vessels, glycol dehydrators, and pneumatic pumps are
demonstrated to be less than 4 tpy.
We are requiring that owners or operators demonstrate that the
source-wide uncontrolled actual VOC emissions from the collection of
all
[[Page 75351]]
crude oil, condensate, intermediate hydrocarbon liquids and produced
water storage vessels, glycol dehydrator process vents, and pneumatic
pumps have been maintained below 4 tpy, using records of monthly
determinations of uncontrolled actual VOC emission rates for the 12
consecutive months immediately preceding the demonstration. The
uncontrolled actual VOC emissions rate must be calculated using a
generally accepted model or calculation methodology.
The final rule requires that the owner or operator re-evaluate the
source-wide uncontrolled actual VOC emissions on a monthly basis. If
the results of the monthly determination show that the uncontrolled
actual VOC emission rate is greater than or equal to 4 tpy, the owner
or operator will have 30 days to switch to the first option specified
and control VOC emissions by at least 95 percent continuously. We are
finalizing an exemption to the VOC emissions control requirements for
each emergency storage vessel that meets the following requirements:
(1) the storage vessel is not used as an active storage vessel; (2) the
owner or operator empties the storage vessel no later than 15 days
after receiving fluids; (3) the storage vessel is equipped with a
liquid level gauge or equivalent device; and (4) records of the use of
each vessel are kept indicating the date the vessel received fluids or
was discovered to have received fluids, the date the vessel was emptied
and the volume of fluids emptied in barrels.
The final VOC emissions control applicability provisions and other
requirements are the same as or comparable on balance with the
requirements in the Utah Permit Requirements and/or Utah Oil and Gas
Rules. The methods for determining applicability of the control
requirements are the same as those in site-specific minor source BACT
analyses in the Utah Permit Requirements. In site-specific approval
orders that have been issued, the UDEQ requires VOC emissions controls
for source-wide emissions from the collection of all storage vessels,
glycol dehydrators, and pneumatic pumps at oil and natural gas sources
\84\ when the source-wide potential for VOC emissions from that
equipment is greater than or equal to 4 tpy. We have also determined
that controlling emissions above the 4 tpy VOC level is cost-effective
and will achieve meaningful emissions reductions on Indian country
lands within the U&O Reservation.\85\ The methods for determining
applicability of the control requirements are comparable on balance
with the UDEQ's recently adopted Utah Oil and Gas Rules, except that
those rules do not consider emissions from or control of pneumatic
pumps.\86\ The reason for this difference is discussed later when we
describe this FIP's requirements for pneumatic pumps. The Utah Oil and
Gas Rules require all new and modified storage vessels (i.e., those
that begin operation on or after January 1, 2018) to control emissions
upon startup of operation for a minimum of one year. The requirement in
this FIP to control emissions from the collection of all new and
modified storage vessels for at least 12 consecutive months, the
exemption for emergency storage vessels, and the provision allowing
removal of controls from the collection of all storage vessels, glycol
dehydrators, and pneumatic pumps are also the same as the requirements
in the Utah Oil and Gas Rules, with the exception of pneumatic pump
emissions and control mentioned earlier, which will be discussed in
more detail later.
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\84\ The docket for this rulemaking contains several examples of
UDEQ site-specific minor source NSR permits (approval orders) for
Crude Oil and Natural Gas Well Sites and/or Tank Batteries (DAQE-
AN151010001-15, DAQE-AN149250001-14, and DAQE-AN143640003-15). UDEQ
site-specific approval order requirements are based on BACT analyses
for oil and natural gas sources concluding that combustion of VOC
emissions from crude oil and condensate storage tanks, glycol
dehydrators, and pneumatic pumps is economically and technically
feasible when the source-wide potential for VOC emissions from those
emissions sources is equal to or greater than 4 tpy. The analyses
rely in part on the EPA's analysis in the April 12, 2013 NSPS OOOO
reconsideration, and the finding that emissions from those three
emissions sources at a single source can feasibly be routed to the
same combustor. Though the 4 tpy threshold is not specifically
stated in the approval orders, if a source applying for a site-
specific approval order has source-wide storage tank, glycol
dehydrator, and pneumatic pump VOC emissions equal to or greater
than 4 tpy, the order contains requirements to control those
emissions.
\85\ The RIA in the docket for this rulemaking (Docket ID No.
EPA-R08-OAR-2015-0709) contains more detailed information on our
analyses.
\86\ In response to an EPA comment on UDEQ's proposal
questioning why issued approval orders and the GAO cover pneumatic
pumps, but the new Utah Oil and Gas Rules do not, the UDEQ stated
that the 2014 Uinta Basin Emissions Inventory indicated that
pneumatic pump emissions constitute an insignificant portion of the
total VOC emissions at Utah-regulated sources in the Basin. The
comments and UDEQ's responses are available in the docket for this
rulemaking (Docket ID No. EPA-R08-OAR-2015-0709).
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We are finalizing the option that the owner or operator capture and
route all subject emissions through a closed-vent system to an enclosed
combustor or flare that is designed and operated to reduce the mass
content of VOC in the emissions vented to it by at least 95.0 percent.
Requirements for closed-vent systems are established under conditions
specified in 40 CFR 49.4176 (VOC emission control requirements for
covers and closed-vent systems), and requirements for operation and
monitoring of control devices are established under conditions
specified in 40 CFR 49.4177 (VOC Emission Control Devices) and 40 CFR
49.4182 (Monitoring Requirements), all of which are discussed in detail
below in the summaries of Covers, Closed-Vent Systems, and VOC Emission
Control Devices and Monitoring Requirements.
We are finalizing the alternative option that the owner or operator
design operations to recover 100 percent of the emissions and recycle
them for use in a process unit or incorporate them into a product.
These control options are the same as the Utah Permit Requirements and
the Utah Oil and Gas Rules.
As described earlier, regulating pneumatic pumps in this U&O FIP is
not comparable to the UDEQ's Utah Oil and Gas Rules, because those
rules do not include requirements for pneumatic pumps.\87\ But the
approach in this U&O FIP to controlling pneumatic pumps by routing
emissions to the same control device that controls emissions from the
collection of all storage vessels and glycol dehydrators is the same as
the UDEQ's approach to controlling pneumatic pumps in site-specific
approval orders issued under Utah Permit Requirements. We are confident
that this approach will help achieve ozone air quality improvements
through this U&O FIP, as the UBEI2017-Update shows that VOC emissions
from pneumatic pumps constitute 16 percent of the total oil and natural
gas-related VOC emissions on Indian country lands within the U&O
Reservation.\88\
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\87\ We note that the Utah Oil and Gas Rules do not contain
requirements for pneumatic pumps. We are finalizing requirements for
pneumatic pumps requirements, as we have identified emissions from
existing pneumatic pumps as being a significant source of VOC
emissions on the Indian country lands within the U&O Reservation.
\88\ By contrast, the UBEI2017-Update shows that there are a
very low number of pneumatic pumps installed and operating on lands
in areas of the Basin where the EPA has approved the UDEQ to
implement the CAA; the UDEQ has stated that this fact is the reason
the Utah Oil and Gas Rules do not have control requirements for
pneumatic pumps (see the response to comments on the UDEQ's proposed
rules in the docket for this rulemaking).
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We do not expect that a substantial number of existing oil and
natural gas sources that would meet the applicability criteria of this
U&O FIP will also be subject to NSPS OOOO or OOOOa, or NESHAP HH.
However, to address any potential regulatory overlap, we are providing
that any affected storage vessels, glycol dehydrators, or pneumatic
pumps that
[[Page 75352]]
are subject to the emissions control requirements in those EPA
standards, are not subject to the requirements in this U&O FIP for such
equipment and activities, including monitoring, recordkeeping, and
reporting requirements associated with such equipment and activities.
2. Covers, Closed-Vent Systems
For affected existing, new, and modified sources that are required
to control emissions from the collection of all storage vessels, glycol
dehydrators and pneumatic pumps per 40 CFR 49.4173 through 49.4175, we
are finalizing in 40 CFR 49.4176 (VOC emission control requirements for
covers and closed-vent systems) to require, as applicable, the use of
covers on all storage vessels, and the use of closed-vent systems with
equipment that captures and routes VOC emissions to the respective
vapor recovery or VOC emission control devices. Because closed-vent
systems are common to control requirements for storage vessels, glycol
dehydrators and pneumatic pumps, we are finalizing these requirements
in a separate section to avoid redundancy. Section 49.4176 also
specifies construction and operational requirements for the covers and
closed-vent systems. The construction and operational requirements for
the covers and closed-vent systems are intended to provide legal and
practical enforceability to ensure that all captured VOC emissions are
routed to the respective vapor recovery or VOC emission control
devices. In addition, for affected existing, new, and modified sources
that are required to control emissions from the collection of all
storage vessels, glycol dehydrators and pneumatic pumps, in 40 CFR
49.4177 (VOC emission control devices) we are finalizing specific
legally and practicably enforceable construction and operational
requirements for enclosed combustors and flares.
We are finalizing in 40 CFR 49.4176 (VOC emission control
requirements for covers and closed-vent systems) the requirement that
each owner or operator equip the openings on each affected storage
vessel with a cover that ensures that flashing, working, standing and
breathing losses are efficiently routed through a closed-vent system to
a vapor recovery system, an enclosed combustor, or a flare. We are
finalizing the requirement that each cover and all openings on the
cover (e.g., access hatches, sampling ports, and gauge wells) form a
continuous barrier over the entire surface area of the crude oil,
condensate, intermediate hydrocarbon liquids or produced water in the
storage vessel. Each cover opening must be secured in a closed, sealed
position (i.e., covered by a gasketed lid or cap) whenever material is
in the storage vessel on which the cover is installed, except when it
is necessary to use an opening to: (1) 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); (2) inspect or sample the material
in the unit; or (3) inspect, maintain, repair, or replace equipment
inside the unit.
We are requiring that all vent lines, connections, fittings,
valves, relief valves, and any other appurtenance employed to contain
and collect emissions and transport them to the vapor recovery or VOC
control equipment be maintained and operated properly at all times, and
that they be designed to operate with no detectable emissions. If a
closed-vent system contains one or more bypass devices that could be
used to divert all or a portion of the emissions from entering the
vapor recovery or VOC control devices, we are requiring that the owner
or operator meet one of the following options for each bypass device:
(1) at the inlet to the bypass device, properly install, calibrate,
maintain, and operate a flow indicator capable of taking periodic
readings and sounding an alarm when the bypass device is open such that
the emissions are being, or could be, diverted away from the control
device and into the atmosphere; or (2) secure the bypass device valve
in the non-diverting position using a car-seal or a lock-and-key type
configuration.
The cover and closed-vent system requirements are comparable on
balance with UDEQ requirements for storage vessels in both the issued
site-specific approval orders and the Utah Oil and Gas Rules. The site-
specific approval orders require storage vessel thief hatches to be
closed and latched except during storage vessel unloading or other
maintenance activities. They also require that thief hatches be
inspected once every three months to ensure that thief hatches are
closed and latched, and that any associated gaskets are in good working
condition. Similarly, the Utah Oil and Gas Rules for storage vessels
require thief hatches to be kept closed and latched except during
unloading or maintenance. The U&O FIP requirements for covers and
closed-vent systems were developed by consulting the cover and closed-
vent system requirements of EPA standards, such as OOOO and OOOOa and
NESHAP HH. For ease of implementation, these requirements provide more
detail than the UDEQ requirements in both the issued site-specific
approval orders and the Utah Oil and Gas Rules but are comparable on
balance with the UDEQ requirements for storage vessels and closed-vent
systems.
3. VOC Emission Control Devices
For existing, new, and modified sources that are required to
control VOC emissions from the collection of all storage vessels,
glycol dehydrators and pneumatic pumps, we are finalizing requirements
in 40 CFR 49.4177 (VOC emission control devices) that each owner or
operator follow the manufacturer's written operating instructions,
procedures and maintenance schedules to ensure the use of good air
pollution control practices for minimizing emissions from each enclosed
combustor and flare. Each flare must be designed and operated according
to the requirements of 40 CFR 60.18(b). Each enclosed combustor must be
designed and operated to reduce the mass content of the VOC in the
natural gas routed to it by at least 95.0 percent continuously. The
control efficiency required for each VOC emissions control device is
the same as the Utah Oil and Gas Rules.
We recognize that the site-specific approval orders issued to
existing sources under the Utah Permit Requirements require control
devices to meet 98 percent VOC control efficiency. But we have
concluded that the differences between this U&O FIP, the Utah Oil and
Gas Rules, and the Utah Permit Requirements are minimal, and all were
designed to achieve a consistent result. The UDEQ requires permittees
of minor oil and natural gas sources to show compliance with 98.0
percent VOC control device control efficiency by routing all exhaust
gas/vapors (from the storage vessels, glycol dehydrators or pneumatic
pumps) to the operating combustor, operating the device according to
the manufacturer's written instructions when gases/vapors are routed to
it, operating the device with no visible emissions, and by performing
tests to visually determine smoke emissions according to EPA Method 22
at 40 CFR part 60, appendix A. The Utah Oil and Gas Rules require at
least 95.0 percent VOC control efficiency and do not specify methods to
ensure no visible emissions but refer to NSPS OOOOa for demonstrating
compliance with the control efficiency requirements. We note that
combustion devices can be designed to meet 98.0 percent control
efficiencies, and can control emissions by 98.0 percent or
[[Page 75353]]
more, on average, in practice when properly operated.\89\ Combustion
devices designed to meet 98.0 percent control efficiency may not,
however, be able to meet this efficiency level continuously in
practice, due to factors such as the variability of field conditions
and downtime.
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\89\ The EPA has reviewed performance tests submitted for 19
different makes/models of combustor control devices and confirmed
they meet the performance requirements in NSPS subpart OOOO and
NESHAP subparts HH and HHH. All reported control efficiencies were
above 99.9 percent at tested conditions. EPA notes that the control
efficiency achieved in the field is likely to be lower than the
control efficiency achieved at a bench test site under controlled
conditions, but these units should be able to continuously meet a
95.0 percent control efficiency level when they are designed,
monitored and operated in a way that ensures effective performance
on a continuous basis. See Combustion Device Performance Testing
Summary Table in the docket for this rule.
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During development of NSPS OOOO and OOOOa, 95.0 percent control
efficiency was determined to be the best system of emission reduction
(BSER) able to be continuously achieved by affected facilities (e.g.,
storage vessels, centrifugal compressors) nationwide. The EPA is aware
that enclosed combustors and flares may be capable of achieving
instantaneous control efficiencies greater than 95.0 percent,\90\ but
in determining BSER the EPA must be confident that the control
efficiency can be achieved continuously by affected facilities
nationwide to which it applies. We are confident that combustors and
flares can meet at least 95.0 percent VOC control efficiency on a
continuous basis when they are designed, monitored and operated in a
way that ensures effective performance on a continuous basis. While the
EPA is aware that combustion devices commonly used to control VOC-
containing gas streams are capable of demonstrating greater than 98.0
percent continuous VOC control efficiency in a controlled performance
testing environment, under ideal conditions, based on widespread and
readily available manufacturer test data,\91\ we are not confident that
the devices can achieve 98.0 percent continuous VOC control efficiency
in the field without stronger flare performance requirements than are
currently in effect today.\92\
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\90\ See ``Oil and Natural Gas Sector New Source Performance
Standards and National Emissions Standards for Hazardous Air
Pollutants reviews, Parts 60 and 63, Response to Public Comments on
Proposed Rule, 76 FR 52738 (Aug. 23, 2011), available at <a href="https://www.regulations.gov">https://www.regulations.gov</a> (Docket ID EPA-HQ-OAR-2010-0505 (Section 2.5.4,
pages 127-128; Section 3.4.1, pages 294-295; and Section 3.5.1,
pages 302-303)).
\91\ See Combustion Device Performance Testing Summary Table in
the docket for this rule.
\92\ The Oil and Natural Gas Sector Climate Review Proposed Rule
is soliciting comment and information that would help us better
understand the cost, feasibility, and emission reduction benefits
associated with establishing a 98 percent control efficiency
requirement for flares in the Crude Oil and Natural Gas source
category, including information on the level of performance being
achieved in practice by flares in the field, what conditions or
factors contribute to malfunctions or poor performance at these
flares, and what measures the EPA could or should require in order
to ensure that flares perform at a 98 percent level of control. See
86 FR 63110 (Nov. 15, 2021).
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We are requiring that all flares installed per this rule be
designed and operated in accordance with applicable requirements in 40
CFR 60.18(b).\93\ We are requiring that all enclosed combustors
installed per this rule be models: (1) that have been tested by the
manufacturer in accordance with specific requirements in NSPS OOOO and
OOOOa; or (2) for which the owner or operator has conducted performance
testing according to the requirements in NSPS OOOO and OOOOa. The Utah
Oil and Gas Rules require that compliance for VOC control devices be
demonstrated by meeting the performance test methods and procedures in
NSPS OOOO. The Utah Oil and Gas Rules do not distinguish between flares
and enclosed combustors. We determined, though, that it was important
to have specific requirements for the different types of control
devices that may be present at oil and natural gas sources on Indian
country lands within the U&O Reservation, because EPA standards
including NSPS OOOO and OOOOa and NESHAP HH make such distinctions for
legal and practical enforceability. Therefore, although for ease of
implementation this FIP's requirements for VOC control devices to
demonstrate compliance with the control efficiency requirements are
more detailed than the state's, they are comparable on balance with the
Utah Oil and Gas Rules that reference such requirements in NSPS OOOO,
as well as with NSPS OOOO and OOOOa and NESHAP HH.
---------------------------------------------------------------------------
\93\ 40 CFR 60.18(b) for flares requires compliance with 40 CFR
60.18(c) through (f).
---------------------------------------------------------------------------
We determined that certain work practice and operational
requirements are also necessary for the practical enforceability of the
VOC emission reduction requirements for flares or enclosed combustors.
We are requiring that flares and enclosed combustors be operated within
specific parameters to ensure the effective control of VOC
emissions.\94\ Specifically, we are requiring that each owner or
operator ensure that each enclosed combustor or flare is: (1) operated
at all times that emissions are routed to it; (2) equipped and operated
with a liquid knockout system to collect any condensable vapors (to
prevent liquids from going through the control device); (3) equipped
and operated with a flashback flame arrestor; (4) equipped and operated
with a continuous burning pilot flame, or an electronically controlled
automatic ignition device; (5) equipped with a monitoring system for
continuous 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 Supervisory Control and Data
Acquisition (SCADA) system, to monitor and document proper operation of
the enclosed combustor or flare; (6) maintained in a leak-free
condition; and (7) operated with no visible smoke emissions. These work
practice and operational requirements are comparable to requirements of
the Utah Oil and Gas Rules with respect to operation of the control
devices with no visible emissions.
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\94\ The necessity of such a requirement was discussed in detail
in the preamble and Technical Support Documents to the proposed and
final NSPS OOOO. These documents can be found in the docket for the
NSPS OOOO rulemaking (Docket ID EPA-HQ-OAR-2010-0505), available at
<a href="https://www.regulations.gov">https://www.regulations.gov</a>.
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To ensure legal and practical enforceability, other work practice
and operational requirements in this U&O FIP are different or more
prescriptive than the Utah Oil and Gas Rules in several areas. For
example, the Utah Oil and Gas Rules require all VOC emissions control
devices simply to be equipped and operated with an operational
automatic ignition device. This U&O FIP, on the other hand, requires
each enclosed combustor or flare to be equipped and operated with
either a continuous burning pilot flame or an electronically controlled
automatic ignition device. Further, under this FIP all enclosed
combustors and flares must be equipped with a monitoring system for
continuous measurement 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 device. The work
practice and operational requirements for VOC control devices in this
U&O FIP were developed by considering the UDEQ requirements for VOC
control devices, in combination with consulting the work practice and
operational requirements for control devices in EPA standards,
including NSPS OOOO and OOOOa and NESHAP HH. Regarding
[[Page 75354]]
the requirement to equip enclosed combustors and flares with either a
continuous burning pilot flame or an electronically controlled
automatic ignition device, provided there is a monitoring system to
indicate proper operation of the device, the EPA has maintained the
position as recently as 2016 that without a continuous ignition source,
there may be periods of uncontrolled emissions, and continuous ignition
sources are designed to combust the flammable portion of the gas
stream, even if the gas stream has a low BTU content.\95\ Therefore, we
have maintained that automatic ignition devices alone may not be
reliable in the field to ensure that there is an ignition source at all
times gas is flowing to a control device, and EPA standards, such as
NSPS OOOO and OOOOa, have commonly required that enclosed combustors be
equipped with continuous burning pilot flames and continuous parameter
monitoring systems to ensure the presence of a flame at all times a gas
stream is routed to the control device. Additionally, since the final
FIP requires compliance with 40 CFR 60.18(c)(2) \96\ of the General
Provisions for 40 CFR part 60 when using a flare, a continuous pilot
flame is required, and we have determined that an equivalent
requirement should be applicable to enclosed combustion control devices
used for controlling emissions from storage vessels and other equipment
at affected oil and natural gas sources.
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\95\ The EPA's Response to Public Comments on the EPA's Oil and
Natural Gas Sector: Emission Standards for New, Reconstructed, and
Modified Sources. 40 CFR part 60, subpart OOOOa. May 2016. Chapter
11--Compliance. Comment Excerpt Number: 17. Pages 188-191 (Docket ID
EPA-HQ-OAR-2010-0505-7632), available at <a href="https://www.regulations.gov">https://www.regulations.gov</a>, accessed Mar. 14, 2022.
\96\ Per 40 CFR 60.18(b).
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We recognize that the UDEQ requires automatic ignition devices on
all combustion devices. In the interest of establishing regulations on
Indian country lands within the U&O Reservation that are comparable on
balance with the UDEQ requirements, we are finalizing a hybrid approach
that allows owners and operators required to control VOC emissions from
the collection of all storage vessels, glycol dehydrators, and
pneumatic pumps the option to use devices that comply with EPA
standards (continuous burning pilot), or to use electronically
controlled automatic ignition devices if the control device is also
equipped with a system that can indicate to the owner and operator that
the automatic ignition device is not operating properly while gas is
being routed to the control device. We expect that these requirements
for control devices will achieve a result comparable to the
requirements for VOC control devices in the Utah Oil and Gas Rules and
will ensure that the control device is operated properly to achieve the
required control efficiency while providing consistency with EPA policy
regarding flares and combustors.
Section 49.4177 allows owners or operators of oil and natural gas
sources, on receiving written approval, to use control devices other
than an enclosed combustor or flare, provided they continuously achieve
at least 95.0 percent VOC control efficiency. We expect that this
provision will allow owners and operators to take advantage of
technological advances in VOC emission control in the oil and natural
gas industry, and that it will provide us with valuable information on
new control technologies.
4. Fugitive Emissions Control
For existing, new, and modified sources, we are finalizing LDAR
requirements in 40 CFR 49.4178 (Fugitive emissions VOC emission control
requirements) that each owner or operator of an oil and natural gas
source conduct periodic inspections of the source to detect leaks from
fugitive emissions components and repair them if either of the
following is true: (1) the collection of fugitive emissions components
is located at an oil and natural gas source that is required to control
VOC emissions according to 40 CFR 49.4173 through 49.4177 of this FIP
(i.e., the source-wide potential for VOC emissions from the collection
of all storage vessels, glycol dehydrators, and pneumatic pumps is
equal to or greater than 4 tpy, as determined according to 40 CFR
49.4173(a)(1)); or (2) the collection of fugitive emissions components
is located at a well site, as defined in 40 CFR 60.5430a, that at any
time has total production greater than 15 boe per day based on a
rolling 12-month average.\97\ Owners and operators of the collection of
fugitive emissions components for which neither of the aforementioned
conditions are true have the option to either (1) implement a program
of periodic fugitive emissions inspections and repair, or (2)
demonstrate that the total daily oil and natural gas production of the
collection of all wells producing to the well site is at or below 1 boe
per day, based on a 12-month rolling average, calculated according to
specific procedures specified in 40 CFR 49.4178(e). Owners and
operators of the collection of fugitive emissions components at an oil
and natural gas source that is subject to the fugitive emissions
monitoring requirements of NSPS OOOOa are exempt from this FIP's
fugitive emissions monitoring requirements for those components.
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\97\ As explained earlier, the Oil and Natural Gas Sector
Climate Review Proposed Rule proposes a different approach for LDAR
applicability based on the level of facility wide methane fugitive
emissions. We are finalizing these requirements in the interest of
taking action now to reduce VOC emissions on the Indian country
lands within the U&O Reservation and recognizing the advantages of
maximizing emissions reductions while providing a measure of
consistency with the UDEQ and federal requirements that are in
effect today. We may revisit this rulemaking in the future based on
any final action we take under CAA section 111 with the Oil and
Natural Gas Sector Climate Review rulemaking.
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We are finalizing a definition of ``fugitive emissions component''
in 40 CFR 49.4171, consistent with the approach in NSPS OOOOa, that
includes valves, connectors, open-ended lines, pressure relief devices,
flanges, covers and closed-vent systems not subject to 40 CFR 49.4173
through 49.4175, thief hatches or other openings on controlled storage
vessels not subject to 40 CFR 49.4173, compressors, instruments and
meters.\98\ Each owner or operator is required to develop and implement
a Reservation-wide fugitive emissions monitoring plan for all of its
affected oil and natural gas sources on Indian country lands within the
U&O Reservation that must include the following elements, at a minimum:
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\98\ 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.
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(1) Conduct an initial monitoring of fugitive emissions components
at each affected source within 12 months of the effective date of the
rule.
(2) Conduct subsequent monitoring once every 6 months after the
initial monitoring for fugitive emissions components at oil and natural
gas sources.
(3) Describe the fugitive emissions detection monitoring method to
be used (limited to onsite optical gas imaging instruments, with a leak
defined as any visible emissions using an optical gas imaging
instrument, EPA Reference Method 21, with an instrument reading of 500
parts per million volume (ppmv) VOC defined as a leak, or another
method approved by the EPA other than optical gas imaging or EPA
Reference Method 21).
(4) Identification of manufacturer and model number of any leak
detection equipment to be used.
[[Page 75355]]
(5) Procedures and timeframes for identifying and repairing
components from which leaks are detected, including a requirement to
repair any identified leaks from components that are safe to repair and
that do not require source shutdown within 30 days of discovering a
leak, and identification of timeframes (which must be no later than the
next required monitoring event after discovering the leak) to repair
leaks that are designated as difficult-to-monitor or unsafe-to-monitor,
or which require source shutdown. If the repair or replacement of a
fugitive emissions component designated difficult-to-monitor or unsafe-
to-monitor is technically infeasible, would require a vent blowdown, a
compressor station shutdown, a well shutdown or shut-in, or would be
unsafe to repair \99\ during operation of the unit, the repair or
replacement must be completed during the next scheduled compressor
station shutdown, well shutdown, well shut-in, after a planned vent
blowdown, or within 2 years, whichever is earlier.
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\99\ ``Unsafe to repair'' is defined in the final rule as
meaning 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.
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(6) Procedures for verifying effective repair of leaking
components, no later than 30 days after repairing a leak.
(7) Specific training and experience needed to perform inspections.
(8) Description of procedures for calibration and maintenance of
any fugitive emissions monitoring device to be used.
(9) Standard monitoring protocols for each type of typical affected
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).
We are finalizing in 40 CFR 49.4179 an exemption for source owners/
operators from having to monitor and repair a fugitive emissions
component under certain circumstances: (1) the contacting process
stream only contains glycol, amine, methanol or produced water; or (2)
the component 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 in a manner that prevents access by a
monitor probe or optical gas imaging device.
The fugitive emissions LDAR requirements in this U&O FIP are
designed to be consistent with those in NSPS OOOOa. In developing the
final FIP LDAR requirements, we also reviewed the UDEQ requirements.
For existing, new, and modified sources subject to the Utah Oil and Gas
Rules, the LDAR requirements were designed to be procedurally
consistent with NSPS OOOOa, though the applicability threshold is
different. The UDEQ's site-specific approval orders, a general approval
order (GAO) for crude oil and natural gas well sites and tank
batteries,\100\ and the Utah Oil and Gas Rules all require
implementation of an LDAR program at facilities that are required to
control storage vessel, dehydrator, and/or pneumatic pump emissions.
The Utah Oil and Gas Rules require semi-annual fugitive emissions
monitoring and repair for any affected source. Existing oil and natural
gas sources that were authorized under the UDEQ's site-specific
approval orders are required to conduct fugitive emissions monitoring
and repair at frequencies ranging from annual to quarterly. Existing
oil and natural gas sources that are authorized under the UDEQ's GAO
are subject to fugitive emissions monitoring at varying frequencies
based on production levels and number of leaks detected.
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\100\ The docket for this rulemaking (Docket ID No. EPA-R08-OAR-
2015-0709) contains an approval for coverage under the GAO for a
Crude Oil and Natural Gas Well Site and/or Tank Battery (DAQE-
MN149250001-14).
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The final FIP applicability threshold is consistent in part with
the UDEQ's LDAR applicability threshold, though the final FIP also
requires any additional sources where daily production exceeds 15 boe
per day to conduct an LDAR inspection program, which is consistent in
part with NSPS OOOOa. The LDAR inspection frequency requirements of
this U&O FIP are the same as the Utah Oil and Gas Rules and NSPS OOOOa.
For oil and natural gas sources that may have obtained coverage under
the UDEQ's approval orders or the GAO, we concluded that the UDEQ's
LDAR inspection frequency requirement is different than the LDAR
inspection frequency requirements for oil and natural gas sources under
this U&O FIP, which may require monitoring frequencies for only certain
sources that are equivalent to this U&O FIP.
We are finalizing a provision allowing for the use of alternative
methods of leak detection, other than EPA Reference Method 21 or
optical gas imaging instrument, to demonstrate compliance with the
fugitive emissions monitoring requirements, provided the method is
approved by the EPA. We are finalizing language specifying that to be
approved by the EPA, a demonstration that the alternative method
achieves emissions reductions that equal or exceed those that would
result from the application of either Method 21 or optical gas imaging
instruments must be made and any proposed approval by the EPA will be
subject to public notice and comment.
5. VOC Emissions Control Requirements for All Sources
Sections 49.4179 (VOC emission control requirements for tank truck
loading), 49.4180 (VOC emission control requirements for pneumatic
controllers) and 49.4181 (Other combustion devices) contain
requirements for all existing, new, and modified existing oil and
natural gas sources, regardless of source-wide or emission-unit-
specific emissions. Like the requirements in Utah's Oil and Gas Rules
for oil and natural gas sources in areas of the Basin where the EPA has
approved the UDEQ to implement the CAA, the U&O FIP's requirements are
as follows: (1) tank trucks used for transporting crude oil,
condensate, intermediate hydrocarbon liquids or produced water must be
loaded using bottom filling or submerged fill pipes; (2) all existing
pneumatic controllers must meet the pneumatic controller standards in
NSPS OOOO at 40 CFR 60.5390(b)(2) and (c)(2) and NSPS OOOOa at 40 CFR
60.5390a(b)(2) and (c)(2); and (3) all existing enclosed combustors,
flares present and operating at sources on a voluntary basis--that is,
those that are not required to control storage vessel, glycol
dehydrator, and pneumatic pump emissions (per 40 CFR 49.4173 through
49.4175)--must be equipped with an electronically controlled automatic
ignition device.
Our requirements for truck loading/unloading diverge in one respect
from what the UDEQ is requiring in the Utah Oil and Gas Rule. The UDEQ
requires that VOC emissions from tank truck loading and unloading at
sources required to control storage vessel emissions be captured using
a vapor capture line and routed to the onsite combustor or a separate
combustor for VOC control. We are not finalizing an equivalent
requirement at this time, as we did not receive sufficient cost and
emissions reduction information during the public comment period for
this rulemaking to sufficiently evaluate the cost effectiveness of such
a requirement for the limited estimated emissions for truck loading/
unloading on Indian country lands within the U&O Reservation, based on
the UBEI2017-
[[Page 75356]]
Update.\101\ The inventory identifies 595 tpy VOC from truck loading/
unloading. Assuming that the annualized cost to install a vapor capture
line to an existing combustor is similar to that of routing pneumatic
pump emissions to a combustor (approximately $1,627 per source) and
assuming that there are approximately 2,165 sources that would be
required to add a combustor, such a requirement to i
[…truncated; see source link]Indexed from Federal Register on December 8, 2022.
This is legal information, not legal advice. Laws vary by jurisdiction and change frequently. Always verify current law with official sources and consult a licensed attorney in your jurisdiction for advice on your specific situation.