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

Federal RegisterDec 8, 2022

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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.

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

www.regulations.gov

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

http://www.regulations.gov,

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:

smith.claudia@epa.gov.

SUPPLEMENTARY INFORMATION:

Definitions

Act

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,

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.

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.

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)

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,

within which the U&O Reservation is located, and where ambient ozone levels have exceeded both the 2008 and the 2015 ozone NAAQS.

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.

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:

https://deq.utah.gov/air-quality/2014-air-agencies-oil-and-gas-emissions-inventory-uinta-basin,

accessed Mar. 11, 2022.

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:

https://www.epa.gov/ozone-pollution/table-historical-ozone-national-ambient-air-quality-standards-naaqs,

accessed Mar. 11, 2022.

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

https://www.epa.gov/ozone-designations/additional-designations-2015-ozone-standards,

accessed Mar. 11, 2022.

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.

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.

See

87 FR 21842 (Apr. 13, 2022), available at

https://www.govinfo.gov/content/pkg/FR-2022-04-13/pdf/2022-07513.pdf,

accessed Apr. 29, 2022.

Additional details on the proposed extension of the attainment date are discussed in Section III.D. of this preamble.

The winter-time ozone formation in the Uinta Basin is caused by emissions of VOC and NO

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

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

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.

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.

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.

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

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))

and that preconstruction review of new major stationary sources and major

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,

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.

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.

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.

Existing sources are sources that commence construction before the effective date of this FIP, per 40 CFR 49.4169(c).

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.

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),

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

would not be beneficial in winter months. The EPA may decide to focus on NO

reductions in future rulemakings if additional action is required to address air quality impacts from ozone pollution in the Basin.

See

Uinta Basin Ozone Studies (field studies conducted in the Basin from 2011 to 2014), available at

https://deq.utah.gov/air-quality/uinta-basin-ozone-studies-ubos,

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).

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”).

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,

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)

(National O&NG FIP). In addition to providing a streamlined construction authorization mechanism to new and modified true minor oil and natural gas sources,

the National O&NG FIP requires compliance with a suite of eight federal oil and natural gas source category emissions standards

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.

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.

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.

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

https://www.regulations.gov,

accessed Mar. 11, 2022.

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.

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.

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

https://www.regulations.gov,

accessed Mar. 11, 2022.

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

beyond those in the National O&NG FIP.

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.

See

81 FR 35964, 35968.

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.

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).

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),

which disapproved policy revisions made in 2020 to NSPS OOOO and OOOOa

and thereby reinstated standards from the 2012 NSPS OOOO and 2016 NSPS OOOOa.

The resolution did not, however, disapprove technical revisions made in a separate rulemaking in 2020 to NSPS OOOOa,

which remain in place today. These two events resulted in regulatory inconsistencies between the NSPS OOOOa methane and VOC standards.

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.

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).

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.

Despite these complications, EPA has focused its analysis for this U&O FIP on the currently applicable state and federal requirements and guidance.

Available at

https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry/2016-control-techniques-guidelines-oil-and,

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.

5 U.S.C. 801-808.

85 FR 57018 (Sept. 14, 2020) (“2020 Policy Rule”; as of June 30, 2021, no longer in effect due to CRA disapproval).

Public Law 17-23 (June 30, 2021) (resolving that Congress “disapproves the [2020 Policy Rule] . . . and such rule shall have no force or effect”).

85 FR 57398 (Sept. 15, 2020) (“2020 Technical Rule”).

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

https://www.epa.gov/system/files/documents/2021-07/qa_cra_for_2020_oil_and_gas_policy_rule.6.30.2021.pdf,

accessed Mar. 11, 2022.

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.

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

https://www.regulations.gov

(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

https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry/epa-issues-supplemental-proposal-reduce.

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.

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

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).

Information available at

https://www.epa.gov/air-emissions-inventories/national-emissions-inventory-nei,

accessed Mar. 11, 2022.

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.

The final rule also contains provisions allowing for the use of alternative methods of leak detection, provided the method is approved by the EPA.

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

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.

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

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.

Available in the docket for this rulemaking (Docket ID No. EPA-R08-OAR-2015-0709).

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.

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]

Present value

Equivalent

annual value

Present value

Equivalent

annual value

3 Percent Discount Rate

Benefits

$1,000

$120

$1,000

$120

3 Percent Discount Rate

7 Percent Discount Rate

Net Compliance Costs

610

560

Compliance Costs

630

580

Product Recovery

Net Benefits

390

440

Non-Monetized Benefits

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 PM

2.5

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.

Values rounded to two significant figures. Totals may not appear to add correctly due to rounding.

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-CH

) (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-CH

at a 3 percent discount rate, but the Agency does not have a single central SC-CH

point estimate. We emphasize the importance and value of considering the benefits calculated using all four SC-CH

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-CH

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.

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

2.5

) 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

2.5

, 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

2.5

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.

Such an analysis would account for the distribution of air pollution-attributable risks among populations most vulnerable and susceptible to PM

2.5

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

2.5

, 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.

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:

https://www.epa.gov/naaqs/particulate-matter-pm-standards-integrated-science-assessments-current-review,

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:

https://www.epa.gov/isa/integrated-science-assessment-isa-ozone-and-related-photochemical-oxidants.

Accessed Mar. 11, 2022.

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,

as well as existing, new, and modified sources

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

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.

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.

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.

As specified at 40 CFR 49.4169(c).

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.

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.

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

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.

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.

Table 2—Source Categories Affected by This Action

Industry category

NAICS code

Examples of regulated entities/description of 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 Extraction

211111

Exploration, development and/or the production of 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 Operations

213112

Performing support activities on a contract or fee 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:

https://www.epa.gov/air-quality-implementation-plans/approved-air-quality-implementation-plans-region-8

(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.

In 1948 Congress extended the exterior boundary of the Reservation with the Hill Creek Extension.

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.

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).

62 Stat. 72 (1948).

See Ute Indian Tribe

Utah,

521 F. Supp. 1072 (D. Utah 1981);

Ute Indian Tribe

Utah,

716 F.2d 1298 (10th Cir. 1983);

Ute Indian Tribe

Utah,

773 F.2d 1087 (10th Cir. 1985) (en banc),

cert. denied,

479 U.S. 994 (1986);

Hagen

Utah,

510 U.S. 399 (1994);

Ute Indian Tribe

Utah,

935 F. Supp. 1473 (D. Utah 1996);

Ute Indian Tribe

Utah,

114 F.3d 1513 (10th Cir. 1997),

cert. denied,

522 U.S. 1107 (1998);

Ute Indian Tribe

Utah,

790 F.3d 1000 (10th Cir. 2015),

cert. denied,

136 S. Ct. 1451 (2016); and

Ute Indian Tribe

Myton,

835 F.3d 1255 (10th Cir. 2016),

cert. dismissed,

137 S. Ct. 2328 (2017);

Hackford

Utah,

845 F.3d 1325, 1327 (10th Cir.), cert. denied, 138 S. Ct. 206 (2017).

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.

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.

Acting principally under that authority, on February 12, 1998, the EPA promulgated the Tribal Authority Rule (TAR).

In the TAR, we determined that it was appropriate to treat eligible tribes in the same manner as states for

all CAA statutory and regulatory purposes, except a list of specified CAA provisions and implementing regulations thereunder.

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).

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 U.S.C. 7601(d)(4).

“Indian Tribes: Air Quality Planning and Management.”

see

63 FR 7254 (Feb. 12, 1998); 40 CFR 49.1-49.11.

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.

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.”

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.”

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.

See

63 FR at 7265 (Feb. 12, 1998).

Id.

40 CFR 49.11(a).

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).

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.”

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.

“Review of New Sources and Modifications in Indian Country,” Proposed Rule, 71 FR 48696 (Aug. 21, 2006).

“Review of New Sources and Modifications in Indian Country,” Final Rule, 76 FR 38748, 38754 (July 1, 2011).

See

76 FR 38748.

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.

Tribes can elect to develop and implement their own EPA-approved program under the TAR but are not required to do so.

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.

40 CFR 49.153. Existing sources are only subject to the registration requirements unless they undergo modification.

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.

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

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.

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.

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,

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.

See

40 CFR 49.153, Table 1.

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).

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

2.5,

and NO

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.

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.

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.”

See

80 FR 65292 (Oct. 26, 2015).

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

https://www.epa.gov/air-trends/ozone-trends,

accessed Mar. 14, 2022.

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.

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.

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.

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.

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.

See

87 FR 21842 (Apr. 13, 2022), available at

https://www.govinfo.gov/content/pkg/FR-2022-04-13/pdf/2022-07513.pdf,

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.

Preliminary air quality data is available at

https://www.epa.gov/outdoor-air-quality-data/download-daily-data,

accessed Apr. 29, 2022.

Ambient ozone is a secondary pollutant formed when the two primary ozone precursors, VOC and NO

, 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

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.

The

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.

These studies found that the oil and natural gas production industry is the most significant anthropogenic contributor of VOC and NO

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

emissions.

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).

“Uinta Basin Ozone Studies (UBOS),”

https://deq.utah.gov/air-quality/uinta-basin-ozone-studies-ubos,

accessed Mar. 11, 2022.

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.

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.

As discussed in the RIA for this final rule (available at

https://www.regulations.gov,

Docket ID #EPA-R08-OAR-2015-0709), adoption of the VOC control measures required under this FIP may result in very small NO

emission increases. We estimate that these additional NO

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

emissions increase will not counteract the effect of the VOC reductions or adversely affect the area's ability to attain the NAAQS.

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.”

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.

See

81 FR at 35963 (June 3, 2016).

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.

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);

(2) a study by the Western Regional Air Partnership (WRAP);

(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;

and (4) EPA Greenhouse Gas Reporting Program, subpart W Petroleum and Natural Gas Systems.

They are discussed in more detail in the Regulatory Impact Analysis (RIA) for this final rule.

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).

See

2017 National Emissions Inventory (2017 NEI), available at

https://www.epa.gov/air-emissions-inventories/2017-national-emissions-inventory-nei-data,

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.

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

http://www.wrapair2.org/PhaseIII.aspx,

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.

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.

EPA Greenhouse Gas Reporting Program (GHGRP) Petroleum and Natural Gas Systems, available at

https://www.epa.gov/ghgreporting/ghgrp-petroleum-and-natural-gas-systems,

accessed Mar. 14, 2022.

The RIA can be viewed in the docket for this rulemaking (Docket ID No. EPA-R08-OAR-2015-0709).

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

contributor of both VOC and NO

emissions in the Uinta Basin, at 97 percent of the VOC emissions and 64 percent of the NO

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.

The calculation excludes biogenic sources of VOC and NO

, 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.

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

(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.

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

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

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.

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.

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,

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.

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.

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.

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.

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.”

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.

See

78 FR 17836 (Mar. 22, 2013).

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.

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.

See

85 FR 3501, Section IV. Developing the Proposed Control Rule, A. Rationale for the Proposed Rule.

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

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.

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

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

emissions in the Uinta Basin.

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.

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).

Based on the NEI Source Type to Sector Crosswalk in the 2017 NEI, available at

https://www.epa.gov/air-emissions-inventories/2017-national-emissions-inventory-nei-data,

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.”

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.

The RIA for the final rule can be viewed in the docket for this rulemaking (Docket ID No. EPA-R08-OAR-2015-0709).

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

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.

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

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

and Utah Permit Requirements

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.

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.

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.

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

Control Requirements

U&O FIP VOC Emissions Controls

Final FIP requirements

(section in 40 CFR

part 49)

Applicability threshold

Control efficiency

(percent)

Utah oil and gas rules and Utah permit

requirements

NSPS OOOO

NSPS OOOOa

NESHAP HH

Storage vessel VOC emission control requirements (§ 49.4173)

Source-wide potential for VOC emissions from the collection of all storage vessels, dehydrators and pneumatic pumps ≥4 tpy

Reduce VOC by 95.0 percent or route to a process

See also VOC emission control devices later in this table (§ 49.4177)

Issued Utah Permit Requirements (BACT for site-specific & general approval orders)—Reduce VOC by 98 percent or route to a process where source-wide uncontrolled actual VOC emissions from the collection of all storage vessels, dehydrators and pneumatic pumps ≥4 tpy

Utah Oil and Gas Rules—Reduce VOC by 95 percent or route to a 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

Reduce VOC by 95.0 percent or route to a process for individual storage vessels with potential for ≥6 tpy per storage vessel constructed, reconstructed or modified after August 23, 2011, and on or before September 18, 2015 (alternatively, no control required if uncontrolled actual VOC emissions maintained <4 tpy)

Reduce VOC by 95.0 percent or route to a process for individual storage vessels with potential for ≥6 tpy per storage vessel constructed, reconstructed or modified after September 18, 2015 (alternatively, no control required if uncontrolled actual VOC emissions maintained <4tpy)

Reduce HAP by 95.0 percent or route to a process for individual storage vessels with potential for flash emissions and actual annual average hydrocarbon liquid throughput ≥79,500 liters/day.

Dehydrators VOC emission control requirements (§ 49.4174)

See VOC emission control devices later in this table (§ 49.4177)

Utah Oil and Gas Rules—Reduce VOC by 95 percent if total uncontrolled actual emissions from the collection of dehydrators and storage vessels ≥4 tpy VOC (does not include pneumatic pump emissions)

Not covered

For units at major HAP sources and non-urban area sources with actual annual average flowrate of natural gas ≥85,000 standard m3/day, reduce HAP by 95.0 percent or route to a process.

Units with actual annual average flowrate of natural gas <85,000 standard m3/day not covered—this is the majority of units on Indian country lands within the U&O Reservation.

Pneumatic pumps VOC emission control requirements (§ 49.4175)

See VOC emission control devices later in this table (§ 49.4177)

Issued Utah Permit Requirements (BACT for site-specific & general approval orders)—Reduce VOC by 98 percent or route to a process where source-wide uncontrolled actual VOC emissions from the collection of storage vessels, dehydrators and pneumatic pumps ≥4 tpy

Utah Oil and Gas Rules does not require control of pneumatic pump emissions

Not covered

Reduce VOC by 95.0 percent (if control device is already on site) or route to a process (if technically feasible) for natural gas-driven diaphragm pneumatic pumps at well sites constructed, reconstructed or modified after September 18, 2015

Zero natural gas emissions for natural gas processing plants constructed after September 18, 2015

Not covered.

Covers and closed-vent system VOC emission control requirements (§ 49.4176)

Source-wide potential for VOC emissions from the collection of all storage vessels, dehydrators and pneumatic pumps ≥4 tpy

100 percent of VOC emissions routed to process or control device

100 percent of storage vessel, dehydrator and pneumatic pump emissions routed to control device or process in issued Utah 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)

100 percent of storage vessel VOC emissions routed to control device or process

100 percent of storage vessel emissions routed to control device or process

100 percent of HAP emissions, if required to control glycol dehydrators and/or storage vessels.

VOC emission control devices (§ 49.4177)

Source-wide potential for VOC emissions from the collection of all storage vessels, dehydrators and pneumatic pumps ≥4 tpy

95.0 percent continuously

98.0 percent continuous VOC control efficiency for Issued Utah Permit Requirements (BACT for site-specific & general approval orders)

95 percent continuous control efficiency for Utah Oil and Gas Rules

95.0 percent continuous VOC control efficiency

If required to control glycol dehydrator or storage vessel HAP emissions, must reduce HAP by 95.0 percent, or maintain <20 parts per million volume (ppmv) or 1 tpy benzene.

Fugitive emissions VOC emission control requirements (§ 49.4178)

Source-wide potential for VOC emissions from the collection of all storage vessels, dehydrators and pneumatic pumps ≥4 tpy

Well site production >15 boe per day (rolling consecutive 12-month average)

NA-Semi-annual surveys

Utah Oil and Gas Rules—semi-annual surveys at all registered well sites required to control storage vessel and/or dehydrator VOC emissions

Issued Utah Permit Requirements (sources exempt from Utah Oil and Gas Rules) require LDAR, ranging from annual to quarterly for all approved (

i.e.,

permitted) oil and natural gas sources, including compressor stations

For natural gas processing plants constructed, reconstructed, or modified after August 23, 2011, and on or before September 18, 2015—LDAR requirements as referenced in NSPS VVa, with periodic EPA Method 21 surveys on specific equipment types

For well sites and compressor stations constructed, reconstructed or modified after September 18, 2015—Fugitive emissions surveys using OGI conducted semiannually (well sites) and quarterly (compressor stations)

For natural gas processing plants constructed, reconstructed or modified after September 18, 2015—LDAR requirements as referenced in NSPS VVa, with periodic EPA Method 21 surveys on specific equipment types

Ensure closed-vent system operates with no detectable emissions if required to control glycol dehydrator or storage vessel HAP emissions.

Tank truck loading VOC emission control requirements (§ 49.4179)

None—applies to all existing sources

NA—Bottom filling or submerged fill pipe

Utah Oil and Gas Rules—more stringent, as capture and control of VOC emissions (95 percent efficiency) required at registered sources required to control storage vessel and glycol dehydrator emissions

Not covered

Not covered.

Pneumatic controllers VOC emission control requirements (§ 49.4180)

NA—meet the standards of NSPS OOOO or OOOOa

Utah Oil and Gas Rules—Meet standards of NSPS OOOO

For continuous bleed natural gas driven pneumatic controllers constructed, reconstructed or modified after October 15, 2013 and on or before September 18, 2015, zero-bleed for processing plants and low-bleed (<6 scfh) elsewhere

For continuous bleed natural gas driven pneumatic controllers constructed, reconstructed or modified after September 18, 2015, zero-bleed for processing plants and low-bleed (<6 scfh) elsewhere

Not covered.

Other combustion devices (§ 49.4181)

NA—must be equipped with automatic ignition device

Utah Oil and Gas Rules—must be equipped with automatic ignition device

Not covered

Not covered.

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

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

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.

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.

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.

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.

The RIA in the docket for this rulemaking (Docket ID No. EPA-R08-OAR-2015-0709) contains more detailed information on our analyses.

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).

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.

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.

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.

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).

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

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

more, on average, in practice when properly operated.

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.

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.

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,

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,

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.

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

https://www.regulations.gov

(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)).

See Combustion Device Performance Testing Summary Table in the docket for this rule.

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).

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).

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.

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.

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.

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

https://www.regulations.gov.

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

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.

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)

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.

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

https://www.regulations.gov,

accessed Mar. 14, 2022.

Per 40 CFR 60.18(b).

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.

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.

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.

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.

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:

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.

(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.

(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

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.

“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.

(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 source

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