Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review

AGENCY:

Environmental Protection Agency (EPA).

ACTION:

Final rule.

SUMMARY:

The Environmental Protection Agency (EPA) is finalizing multiple actions to reduce air pollution emissions from the Crude Oil and Natural Gas source category. First, the EPA is finalizing revisions to the new source performance standards (NSPS) regulating greenhouse gases (GHGs) and volatile organic compounds (VOCs) emissions for the Crude Oil and Natural Gas source category pursuant to the Clean Air Act (CAA). Second, the EPA is finalizing emission guidelines (EG) under the CAA for states to follow in developing, submitting, and implementing state plans to establish performance standards to limit GHG emissions from existing sources (designated facilities) in the Crude Oil and Natural Gas source category. Third, the EPA is finalizing several related actions stemming from the joint resolution of Congress, adopted on June 30, 2021, under the Congressional Review Act (CRA), disapproving the EPA's final rule titled, “Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources Review,” September 14, 2020 (“2020 Policy Rule”). Fourth, the EPA is finalizing a protocol under the general provisions for optical gas imaging (OGI).

DATES:

This final rule is effective on May 7, 2024. The incorporation by reference (IBR) of certain publications listed in the rules is approved by the Director of the Federal Register as of May 7, 2024.

ADDRESSES:

The EPA has established a docket for this rulemaking under Docket ID No. EPA–HQ–OAR–2021–0317. All documents in the docket are listed on the https://www.regulations.gov/ website. Although listed, some information is not publicly available, e.g., Confidential Business Information (CBI) or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, is not placed on the internet and will be publicly available only in hard copy form. Publicly available docket materials are available electronically through https://www.regulations.gov/.

FOR FURTHER INFORMATION CONTACT:

Ms. Amy Hambrick, Sector Policies and Programs Division (E143–05), Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency, 109 T.W. Alexander Drive, P.O. Box 12055, Research Triangle Park, North Carolina, 27711; telephone number: (919) 541–0964; email address: hambrick.amy@epa.gov.

SUPPLEMENTARY INFORMATION:

Preamble acronyms and abbreviations. Throughout this document the use of “we,” “us,” or “our” is intended to refer to the EPA. We use multiple acronyms and terms in this preamble. While this list may not be exhaustive, to ease the reading of this preamble and for reference purposes, the EPA defines the following terms and acronyms here:

AMEL alternative means of emission limitation

ANSI American National Standards Institute

API American Petroleum Institute

ARPA–E Advanced Research Projects Agency–Energy

ASME American Society of Mechanical Engineers

ASTM ASTM, International

AVO audible, visual, and olfactory

AWP alternative work practice

bbl barrels of crude oil

BLM Bureau of Land Management

boe barrels of oil equivalents

BOEM Bureau of Ocean Energy Management

BSER best system of emission reduction

Btu/scf British thermal units per standard cubic foot

°C degrees Celsius

CAA Clean Air Act

CBI Confidential Business Information

CCR Code of Colorado Regulations

CDX EPA's Central Data Exchange

CEDRI Compliance and Emissions Data Reporting Interface

CFR Code of Federal Regulations

CO carbon monoxide

CO₂  carbon dioxide

CO₂  Eq. carbon dioxide equivalent

COS carbonyl sulfide

CRA Congressional Review Act

CS₂  carbon disulfide

CVS closed vent systems

D.C. Circuit U.S. Court of Appeals for the District of Columbia Circuit

DOE Department of Energy

EAV equivalent annual value

EDF Environmental Defense Fund

EG emission guidelines

EIA U.S. Energy Information Administration

EJ environmental justice

E.O. Executive Order

EPA Environmental Protection Agency

ESD emergency shutdown devices

°F degrees Fahrenheit

FEAST Fugitive Emissions Abatement Simulation Toolkit

FR Federal Register

FrEDI EPA's Framework for Evaluating Damages and Impacts model

FRFA final regulatory flexibility analysis

g/hr grams per hour

GHG greenhouse gas

GHGI Inventory of U.S. Greenhouse Gas Emissions and Sinks

GHGRP Greenhouse Gas Reporting Program

GOR gas-to-oil ratio

H₂ S hydrogen sulfide

HAP hazardous air pollutant(s)

ICR information collection request

IRFA initial regulatory flexibility analysis

IWG Interagency Working Group on the Social Cost of Greenhouse Gases

kg kilograms

kg/hr kilograms per hour

kt kilotons

lb/yr pounds per year

low-E low emission

LDAR leak detection and repair

LPE legally and practicably enforceable

Mcf thousand cubic feet

MW megawatt

NAAQS national ambient air quality standards

NAICS North American Industry Classification System

NDE no detectable emissions

NIE no identifiable emissions

NESHAP national emission standards for hazardous air pollutants

NGO non-governmental organization

NHV net heating value

NO_X  nitrogen oxides

NSPS new source performance standards

NTTAA National Technology Transfer and Advancement Act

O₂  oxygen

OAQPS Office of Air Quality Planning and Standards

OGI optical gas imaging

OMB Office of Management and Budget

PM particulate matter

PM_2.5  particulate matter with a diameter of 2.5 micrometers or less

ppb parts per billion

ppm parts per million

PRA Paperwork Reduction Act

PSD prevention of significant deterioration

PTE potential to emit

PV present value

REC reduced emissions completion

RFA Regulatory Flexibility Act

RIA regulatory impact analysis

RTC response to comments

RULOF remaining useful life and other factors

SBAR Small Business Advocacy Review

SC–CH₄  social cost of methane

SC–CO₂  social cost of carbon dioxide

SC–GHG social cost of greenhouse gases

SC–N₂ O social cost of nitrous oxide

scf standard cubic feet

scfh standard cubic feet per hour

scfm standard cubic feet per minute

SIP State Implementation Plan

SO2 sulfur dioxide

SPeCS State Planning Electronic Collaboration System

tpy tons per year

the court U.S. Court of Appeals for the District of Columbia Circuit

TAR Tribal Authority Rule

TIP Tribal Implementation Plan

TSD technical support document

UMRA Unfunded Mandates Reform Act

U.S. United States

VCS voluntary consensus standards

VOC volatile organic compound(s)

VRU vapor recovery unit

Organization of this document. The information in this preamble is organized as follows:

I. General Information

A. Does this action apply to me?

B. Where can I get a copy of this document and other related information?

C. Judicial Review and Administrative Review

II. Executive Summary

A. Purpose of the Regulatory Actions

B. Summary of the Major Provisions of This Regulatory Action

C. Costs and Benefits

III. Air Emissions From the Crude Oil and Natural Gas Sector and Public Health and Welfare

A. Impacts of GHGs, VOCs, and SO₂ Emissions on Public Health and Welfare

B. Profile of the Oil and Natural Gas Industry and Its Emissions

IV. Statutory Background and Regulatory History

A. Statutory Background of CAA Sections 111(b), 111(d), and General Implementing Regulations

B. What is the regulatory history and litigation background of NSPS and EG for the oil and natural gas industry?

C. Congressional Review Act (CRA) Joint Resolution of Disapproval

V. Legal Basis for Final Rule Scope

A. Introduction

B. Overview

C. Comments

D. Response to Comments and Discussion

VI. Other Actions and Related Efforts

A. Related State Actions and Other Federal Actions Regulating Oil and Natural Gas Sources

B. Industry and Voluntary Actions To Address Climate Change

C. Methane Emissions Reduction Program

VII. Summary of Engagement With Pertinent Stakeholders

VIII. Overview of Control and Control Costs

A. Control of Methane and VOC Emissions in the Crude Oil and Natural Gas Source Category—Overview

B. How does the EPA evaluate control costs in this final action?

IX. Interaction of the Rules and Response to Significant Comments Thereon

A. What date defines a new, modified, or reconstructed source for purposes of the final NSPS OOOOb?

B. What date defines an existing source for purposes of the final EG OOOOc?

C. How will the final EG OOOOc impact sources already subject to NSPS KKK, NSPS OOOO, or NSPS OOOOa?

X. Summary of Final Standards NSPS OOOOb and EG OOOOc

A. Fugitive Emissions From Well Sites, Centralized Production Facilities, and Compressor Stations

B. Advanced Methane Detection Technology Work Practices

C. Super Emitter Program

D. Process Controllers

E. Pumps

F. Wells and Associated Operations

G. Centrifugal Compressors

H. Combustion Control Devices

I. Reciprocating Compressors

J. Storage Vessels

K. Covers and Closed Vent Systems

L. Equipment Leaks at Natural Gas Processing Plants

M. Sweetening Units

N. Electronic Reporting

O. Prevention of Significant Deterioration and Title V Permitting

XI. Significant Comments and Changes Since Supplemental Proposal for NSPS OOOOb and EG OOOOc

A. Fugitive Emissions from Well Sites, Centralized Production Facilities, and Compressor Stations

B. Advanced Methane Detection Technology Work Practices

C. Super Emitter Program

D. Process Controllers

E. Pumps

F. Wells and Associated Operations

G. Centrifugal Compressors

H. Combustion Control Devices

I. Reciprocating Compressors

J. Storage Vessels

K. Covers and Closed Vent Systems

L. Equipment Leaks at Natural Gas Processing Plants

M. Sweetening Units

XII. Significant Comments and Changes Since Proposal for NSPS OOOOa and NSPS OOOO

A. Low Production Well Site Exemption Rescission

B. Compressor Station Quarterly Monitoring

C. Delay-of-Repair Provisions

D. Applicability/Scope of the Rule

XIII. Significant Comments and Changes to Emission Guidelines for State, Tribal, and Federal Plan Development for Existing Sources

A. Overview

B. Components of EG

C. Establishing Standards of Performance in State Plans

D. Components of State Plan Submission

E. Timing of State Plan Submissions and Compliance Times

F. EPA Action on State Plans and Promulgation of Federal Plans

G. Tribes and the Planning Process Under CAA Section 111(d)

XIV. Use of Optical Gas Imaging in Leak Detection (Appendix K) and Response to Significant Comments

A. Changes Since Supplemental Proposal

B. Summary of Requirements

XV. Prevention of Significant Deterioration and Title V Permitting

XVI. Summary of Cost, Environmental, and Economic Impacts

A. What are the air quality impacts?

B. What are the secondary impacts?

C. What are the cost impacts?

D. What are the economic impacts?

E. What are the benefits?

F. What analyses of environmental justice did we conduct?

XVII. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review and Executive Order 14094: Modernizing 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) and 1 CFR Part 51

J. Executive Order 12898: Federal Actions To Address Environmental Justice in Minority Populations and Low-Income Populations and Executive Order 14096: Revitalizing Our Nation's Commitment to Environmental Justice for All

K. Congressional Review Act (CRA)

I. General Information

A. Does this action apply to me?

The source category that is the subject of this final rulemaking is composed of the Crude Oil and Natural Gas source category regulated under CAA section 111 New Source Performance Standards and Emission Guidelines. The North American Industry Classification System (NAICS) codes for the industrial source category affected by the NSPS actions finalized in this rulemaking are summarized in table 1. The NAICS codes serve as a guide for readers outlining the type of entities that the final NSPS actions are likely to affect. The NSPS codified in 40 Code of Regulations (CFR) part 60, subpart OOOOb, are directly applicable to affected facilities that begin construction, reconstruction, or modification after December 6, 2022. Final amendments to 40 CFR part 60, subpart OOOO, are applicable to affected facilities that began construction, reconstruction, or modification after August 23, 2011, and on or before September 18, 2015. Final amendments to 40 CFR part 60, subpart OOOOa, are applicable to affected facilities that began construction, reconstruction, or modification after September 18, 2015, and on or before December 6, 2022. As shown in table 1, Federal, state, and local government entities would not be affected by the NSPS actions.

This table is not intended to be exhaustive but rather provides a guide for readers regarding entities likely to be affected by the NSPS actions. Other types of entities not listed in the table could also be affected by these NSPS actions. To determine whether your entity is affected by any of the NSPS actions, you should carefully examine the applicability criteria found in the final NSPS rules. If you have questions regarding the applicability of the NSPS rules to a particular entity, consult the person listed in the FOR FURTHER INFORMATION CONTACT section, your state air pollution control agency with delegated authority for NSPS, or your EPA Regional Office.

The issuance of CAA section 111(d) final EG does not impose binding requirements directly on existing sources. The EG codified in 40 CFR part 60, subpart OOOOc, applies to states in the development, submittal, and implementation of state plans to establish performance standards to reduce emissions of GHGs from designated facilities that are existing sources on or before December 6, 2022. Under the Tribal Authority Rule (TAR), eligible Tribes may seek approval to implement a plan under CAA section 111(d) in a manner similar to a state. See 40 CFR part 49, subpart A. Tribes may, but are not required to, seek approval for treatment in a manner similar to a state for purposes of developing a Tribal implementation plan (TIP) implementing the EG codified in 40 CFR part 60, subpart OOOOc. The TAR authorizes Tribes to develop and implement their own air quality programs, or portions thereof, under the CAA. However, it does not require Tribes to develop a CAA program. Tribes may implement programs that are most relevant to their air quality needs. If a Tribe does not seek and obtain the authority from the EPA to establish a TIP, the EPA has the authority to establish a Federal CAA section 111(d) plan for designated facilities that are located in areas of Indian country. A Federal plan would apply to all designated facilities located in the areas of Indian country covered by the Federal plan unless and until the EPA approves a TIP applicable to those facilities.

B. Where can I get a copy of this document and other related information?

In addition to being available in the docket, at Docket ID No. EPA–HQ–OAR–2021–0317 located at https://www.regulations.gov/, an electronic copy of this final rulemaking is available on the internet at https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry. Following signature by the EPA Administrator, the EPA will post a copy of this final rulemaking at this same website. Following publication in the Federal Register , the EPA will post the Federal Register version of the final rulemaking and key technical documents at this same website.

C. Judicial Review and Administrative Review

Under Clean Air Act (CAA) section 307(b)(1), judicial review of this final rulemaking is available only by filing a petition for review in the United States Court of Appeals for the District of Columbia Circuit by May 7, 2024. Under CAA section 307(b)(2), the requirements established by this final rulemaking may not be challenged separately in any civil or criminal proceedings brought by the EPA to enforce the requirements.

Section 307(d)(7)(B) of the CAA further provides that “[o]nly an objection to a rule or procedure which was raised with reasonable specificity during the period for public comment (including any public hearing) may be raised during judicial review.” This section also provides a mechanism for the EPA to convene a proceeding for reconsideration, “[i]f the person raising an objection can demonstrate to the EPA that it was impracticable to raise such objection within [the period for public comment] or if the grounds for such objection arose after the period for public comment, (but within the time specified for judicial review) and if such objection is of central relevance to the outcome of the rule.” Any person seeking to make such a demonstration to us should submit a Petition for Reconsideration to the Office of the Administrator, U.S. Environmental Protection Agency, Room 3000, WJC West Building, 1200 Pennsylvania Ave. NW, Washington, DC 20460, with a copy to both the person(s) listed in the preceding FOR FURTHER INFORMATION CONTACT section, and the Associate General Counsel for the Air and Radiation Law Office, Office of General Counsel (Mail Code 2344A), U.S. Environmental Protection Agency, 1200 Pennsylvania Ave. NW, Washington, DC 20460.

II. Executive Summary

A. Purpose of the Regulatory Actions

On November 15, 2021, the EPA published a proposed rule (“November 2021 Proposal”) to mitigate climate-destabilizing pollution and protect human health by reducing greenhouse gas (GHG) and VOC emissions from the oil and natural gas industry, specifically the Crude Oil and Natural Gas source category. In the November 2021 Proposal, the EPA proposed new standards of performance under section 111(b) of the CAA for GHGs (in the form of methane limitations) and VOC emissions from new, modified, and reconstructed sources in this source category, as well as revisions to standards of performance already codified at 40 CFR part 60, subparts OOOO and OOOOa. The EPA also proposed EG under section 111(d) of the CAA for GHGs emissions (in the form of methane limitations) from existing sources (designated facilities). The new CAA section 111 NSPS and EG would be codified in 40 CFR part 60 at subpart OOOOb (NSPS OOOOb) and subpart OOOOc (EG OOOOc), respectively. The EPA also proposed several related actions stemming from the joint resolution of Congress, adopted on June 30, 2021, under the CRA disapproving the EPA's final rule titled, “Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources Review,” September 14, 2020 (“2020 Policy Rule”). Lastly, in the November 2021 Proposal the EPA proposed a protocol under the general provisions for OGI.

On December 6, 2022, the EPA published a supplemental proposed rule (“December 2022 Supplemental Proposal”) that was composed of two main additions. First, the EPA updated, strengthened, and expanded on the NSPS OOOOb standards proposed in November 2021 under CAA section 111(b) for GHGs (in the form of methane limitations) and VOC emissions from new, modified, and reconstructed facilities. Second, the EPA updated, strengthened, and expanded the presumptive standards proposed for EG OOOOc in the November 2021 Proposal as part of the CAA section 111(d) EG for GHGs emissions (in the form of methane limitations) from designated facilities. For purposes of EG OOOOc, the EPA also proposed the implementation requirements for state plans developed to limit GHGs pollution (in the form of methane limitations) from designated facilities in the Crude Oil and Natural Gas source category under CAA section 111(d).

The purpose of this final rulemaking is to finalize these multiple actions to reduce air emissions from the Crude Oil and Natural Gas source category. First, the EPA finalizes NSPS OOOOb regulating GHG (in the form of a limitation on emissions of methane) and VOCs emissions for the Crude Oil and Natural Gas source category pursuant to CAA section 111(b)(1)(B). Second, the EPA finalizes the presumptive standards in EG OOOOc to limit GHGs emissions (in the form of methane limitations) from designated facilities in the Crude Oil and Natural Gas source category, as well as requirements under the CAA section 111(d) for states to follow in developing, submitting, and implementing state plans to establish performance standards. Third, the EPA finalizes several related actions stemming from the joint resolution of Congress, adopted on June 30, 2021, under the CRA, disapproving the 2020 Policy Rule. Fourth, the EPA finalizes a protocol under the general provisions of 40 CFR part 60 for OGI.

These final actions stem from the EPA's authority and obligation under CAA section 111 to directly regulate categories of new stationary sources that cause or contribute to endangerment from air pollution and to promulgate EG for states to follow in regulating existing sources (designated facilities) in the source category. This final rulemaking takes a significant step forward in mitigating climate-destabilizing pollution and protecting human health by reducing GHG and VOC emissions from the oil and natural gas industry, specifically the Crude Oil and Natural Gas source category. These mitigations are based on proven, cost-effective technologies already required by prior EPA regulations or states' regulations or deployed by industry leaders to reduce this dangerous pollution. The final rules will also encourage the deployment of innovative technologies that currently exist to rapidly and cost-effectively detect and reduce methane pollution and promote further innovation that is already under way to find even more efficient and effective ways to mitigate this pollution. Because methane is the main component of natural gas, the rules also result in more saleable product.

The oil and natural gas industry is the United States' largest industrial emitter of methane, a highly potent GHG. Emissions of methane from human activities are responsible for about one-third of the warming due to well-mixed GHGs and constitute the second most important warming agent arising from human activity after carbon dioxide (CO₂ ). According to the Intergovernmental Panel on Climate Change (IPCC), strong, rapid, and sustained methane reductions are critical to reducing near-term disruption of the climate system as well as a vital complement to reductions in other GHGs that are needed to limit the long-term extent of climate change and its destructive impacts. The oil and natural gas industry also emits other harmful pollutants in varying concentrations and amounts, including CO₂, VOC, sulfur dioxide (SO₂), nitrogen oxides (NO_X), hydrogen sulfide (H₂ S), carbon disulfide (CS₂), and carbonyl sulfide (COS), as well as benzene, toluene, ethylbenzene, and xylenes (this group is commonly referred to as “BTEX”), and n -hexane.

Under the authority of CAA section 111, this rulemaking finalizes comprehensive standards of performance for GHG emissions (in the form of methane limitations) and VOC emissions for new, modified, and reconstructed sources in the Crude Oil and Natural Gas source category, including sources located in the production, processing, and transmission and storage segments. For designated facilities, this rulemaking finalizes EG containing presumptive standards for GHG in the form of methane limitations. States must follow these EG to submit to the EPA plans that establish standards of performance for designated facilities and provide for implementation and enforcement of such standards. The EPA will provide support for states in developing their plans to reduce methane emissions from designated facilities within the Crude Oil and Natural Gas source category. Under the TAR, eligible Tribes may seek approval to implement a plan under CAA section 111(d) in a manner similar to a state. See 40 CFR part 49, subpart A. Tribes may, but are not required to, seek approval for treatment in a manner similar to a state for purposes of developing a TIP implementing the EG codified in 40 CFR part 60, subpart OOOOc. The TAR authorizes Tribes to develop and implement one or more of their own air quality programs, or portions thereof, under the CAA. However, it does not require Tribes to develop a CAA program. Tribes may implement programs that are most relevant to their air quality needs. If a Tribe does not seek and obtain the authority from the EPA to establish a TIP, the EPA has the authority to establish a Federal CAA section 111(d) plan for designated facilities that are located in areas of Indian country. A Federal plan would apply to all designated facilities located in the areas of Indian country covered by the Federal plan unless and until the EPA approves a TIP applicable to those facilities.

The EPA is finalizing these actions in accordance with its legal obligations and authorities following a review directed by Executive Order (E.O.) 13990, “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis,” issued on January 20, 2021. These final actions address the harmful consequences of climate change, which is already resulting in severe and growing human and economic costs within the United States (and globally too). According to the IPCC AR6 assessment, “It is unequivocal that human influence has warmed the atmosphere, ocean and land. Widespread and rapid changes in the atmosphere, ocean, cryosphere and biosphere have occurred.” The IPCC AR6 assessment states that these changes have led to increases in heat waves and wildfire weather, reductions in air quality, more intense hurricanes and rainfall events, and rising sea level. These changes, along with future projected changes, endanger the physical survival, health, economic well-being, and quality of life of people living in the United States (U.S.), especially those in the most vulnerable communities.

Methane is both the main component of natural gas and a potent GHG. Using one standard metric (the 100-year global warming potential (GWP), which is a measure of the climate impact of emissions of 1 ton of a GHG over 100 years relative to the impact of the emissions of 1 ton of CO₂ over the same time frame), methane has about 30 times as much climate impact as CO₂ . Because methane has a shorter lifetime than CO₂, it has a larger relative impact over shorter time frames, and a smaller one over longer time frames: the IPCC AR6 assessment found that “Over time scales of 10 to 20 years, the global temperature response to a year's worth of current emissions of SLCFs [short lived climate forcers] is at least as large as that due to a year's worth of CO₂ emissions.” The IPCC estimated that, depending on the reference scenario, collective reductions in these SLCFs (methane, ozone precursors, and hydrofluorocarbons (HFCs)) could reduce warming by 0.2 degrees Celsius (°C) (more than one-third of a degree Fahrenheit (°F) in 2040 and 0.8 °C (almost 1.5 °F) by the end of the century. As methane is the most important SLCF, this makes methane mitigation one of the best opportunities for reducing near-term warming. Emissions from human activities have already more than doubled atmospheric methane concentrations since 1750, and that concentration has been growing larger at record rates in recent years. In the absence of additional reduction policies, methane emissions are projected to continue rising through at least 2040.

Methane's radiative efficiency means that immediate reductions in methane emissions, including from sources in the Crude Oil and Natural Gas source category, can help reduce near-term warming. As natural gas is composed primarily of methane, every natural gas leak or intentional release of natural gas through venting or other processes constitutes a release of methane. Reducing human-caused methane emissions, such as controlling natural gas leaks and releases through the measures in this final action, is critical to addressing climate change and its effects. See section III of this preamble for further discussion on the air emissions from the Crude Oil and Natural Gas source category climate change, including discussion of the impacts of GHGs, VOCs, and SO₂ emissions on public health and welfare.

Methane and VOC emissions from the Crude Oil and Natural Gas source category result from a variety of industry operations across the supply chain. As natural gas moves through the necessarily interconnected system of exploration, production, storage, processing, and transmission that brings it from wellhead to commerce, emissions primarily result from intentional venting, unintentional gas carry-through ( e.g., vortexing from separator drain, improper liquid level settings, liquid level control valve on an upstream separator or scrubber does not seal properly at the end of an automated liquid dumping event, inefficient separation of gas and liquid phases occurring upstream of tanks allowing some gas carry-through), routine maintenance, unintentional fugitive emissions, flaring, malfunctions, abnormal process conditions, and system upsets. These emissions are associated with a range of specific equipment and practices, including leaking valves, connectors, and other components at well sites and compressor stations; leaks and vented emissions from storage vessels; releases from natural gas-driven pumps and natural gas-driven process controllers; liquids unloading at well sites; and venting or under-performing flaring of associated gas from oil wells. But technical innovations have produced a range of technologies and best practices to monitor, eliminate, or minimize these emissions, which in many cases have the benefit of reducing multiple pollutants at once and recovering saleable product. These technologies and best practices have been deployed by individual oil and natural gas companies, required by state regulations, or reflected in regulations issued by the EPA and other Federal agencies.

In developing this final rulemaking, the EPA applied the latest available information to finalize the analyses presented in the December 2022 Supplemental Proposal. This latest information provided additional insights into lessons learned from states' regulatory efforts, the emission reduction efforts of leading companies, the continued development of new and developing technologies, and information and data from peer-reviewed literature and emission measurement efforts across the U.S.

In both the November 2021 Proposal and the December 2022 Supplemental Proposal, the EPA solicited comment on various aspects of the proposed rules. This final rulemaking responds to the nearly one million total public comments the Agency received. A wide range of stakeholders, including state and local governments, Tribal nations, representatives of the oil and natural gas industry, communities affected by oil and gas pollution, environmental and public health organizations, submitted public comments on both the November 2021 Proposal and the December 2022 Supplemental Proposal. Following the November 2021 Proposal, over 470,000 public comments were submitted. After the December 2022 Supplemental Proposal, over 515,000 additional public comments were submitted. Many commenters representing diverse perspectives expressed general support for the proposals and requested that the EPA further strengthen the proposed rules and make them more comprehensive. Other commenters highlighted implementation or cost concerns related to elements of both proposals or provided specific data and information that the EPA was able to use to refine or revise several of the proposed standards included in the December 2022 Supplemental Proposal.

This final action also builds on extensive engagement with states, Tribes, and a broad range of stakeholders. The EPA conducted stakeholder trainings after both the November 2021 Proposal and the December 2022 Supplemental Proposal for communities with environmental justice (EJ) concerns, Tribes, and small businesses. The EPA held 3-day virtual public hearings for both the November 2021 Proposal and the December 2022 Supplemental Proposal with over 600 speakers and hundreds of viewers on livestream. Tribal consultations were completed after the November 2021 Proposal at the request of the Northern Arapahoe Tribe, Mandan, Hidatsa and Arikara Nation (MHA Nation), and Eastern Shoshone Tribe. Additional Tribal consultation was completed at the request of MHA Nation and an informational meeting was held with the Ute Tribe after the December 2022 Supplemental Proposal. Through this stakeholder engagement, the EPA heard from diverse voices and perspectives, all of which provided ideas and information that helped shape and inform this final rulemaking.

In this final rulemaking, the EPA is finalizing updates to various aspects of the proposed rules because of the information received through the public comment process. For example, after review of the comments, the EPA is finalizing updates to allow owners and operators the option to use advanced methane monitoring technologies for detecting fugitive emissions. All stakeholders supported allowing for the use of alternative technologies and provided the EPA with constructive feedback and information to help finalize this aspect of the rulemaking, along with improvements that provide greater flexibility for owners and operators while ensuring these technologies are used in an effective way to detect methane emissions. Among other things, the EPA is finalizing changes from the December 2022 Supplemental Proposal that will allow owners and operators to use multiple advanced technologies in combination, and facilitate the use of the best advanced technologies that we know of by streamlining certain of the proposed monitoring requirements associated with their use. The EPA is also finalizing an efficient pathway for demonstrating that new technologies meet the performance requirements established under this rulemaking, and approving their use under this program. The final rulemaking allows for either a periodic screening approach or a continuous monitoring approach. The EPA believes this program will allow owners and operators to leverage advanced technologies that are already available to detect methane emissions rapidly with accuracy, as well as to incorporate promising new technologies that are emerging in this rapidly evolving field.

As a result of information provided through the public comment process, the EPA is also finalizing revisions to the proposed requirements for new sources to limit routine flaring of associated gas. During the comment period, the EPA received extensive information regarding alternatives to routine flaring, state-level requirements to limit or prohibit routine flaring, and commitments that owners and operators have already made voluntarily to phase out routine flaring in the near future. Based on this information and the EPA's updated BSER analysis, the EPA is finalizing requirements that will phase out and eventually prohibit routine flaring of associated gas from newly constructed wells that are developed after the effective date of this rule. These requirements include reasonable exemptions for certain temporary and emergency uses of flaring, and a transition period to allow owners and operators adequate time to incorporate this requirement into their development plans and to deploy any necessary equipment and controls. For a subcategory of existing wells (with documented methane of 40 tons per year (tpy) or less), the EPA is finalizing modifications to its December 2022 Supplemental Proposal to allow routine flaring. This approach reflects information the EPA received during this rulemaking, and the EPA's updated BSER analysis, that indicates that alternatives to routine flaring at such wells are generally costly and could be technically challenging to implement, while achieving relatively small emission reductions. For higher-emitting existing (above 40 tpy methane), modified, and reconstructed wells, the EPA is finalizing the provisions proposed in the December 2022 Supplemental Proposal limiting routine flaring to situations in which a sales line to collect the associated gas is not available, and the owner and operator has submitted a demonstration that other alternatives to routine flaring are not available due to technical infeasibility. With the updates made in this final rulemaking in response to comments, the EPA believes that the final rules and emission guidelines provide an approach to limiting routine flaring from associated gas that achieves significant reductions in emissions, while also providing owners and operators with flexibility to utilize routine flaring where needed and sufficient lead time to implement alternatives to routine flaring at newly developed wells.

Further, the EPA is finalizing, with certain revisions, requirements proposed in the December 2022 Supplemental Proposal to monitor flares to ensure proper operation and assure continual compliance. Improperly operating flares are a well-documented large source of emissions, and requiring operators to monitor and fix these problems will yield significant methane reductions.

In addition, the EPA is finalizing a Super Emitter Program as part of this rulemaking that requires owners and operators to take appropriate action to investigate very large emissions events upon receiving from the EPA a notification from a certified entity, and if necessary, take steps to ensure compliance with the applicable regulation(s). The EPA has made important modifications to this program based on comments received on the December 2022 Supplemental Proposal. Public comments informed the EPA that there is widespread recognition of the need to address super-emitters, that it is critical for the EPA to have a central role in the program, and that timely information-sharing and response is key to being able to achieve emission reductions. As a result, the final Super Emitter Program provides a central role for the EPA in receiving notifications from certified third parties and verifying that these notifications are complete and have properly documented the existence of a super-emitting event before sending them to the appropriate owner or operator. In addition, as proposed, the EPA will have a central role in approving monitoring technologies, certifying and de-certifying notifiers, requiring that third parties submit notifications within a limited timeframe, and obligating operators to subsequently respond in a timely manner. These targeted changes for the Super Emitter Program are intended to ensure that the program operates with a high degree of accuracy, integrity, and transparency, while providing owners and operators with prompt and reliable notifications of super-emitting events that may require follow-up investigation and remediation. See sections X and XI of this preamble for a full summary and rationale of the changes since proposal.

After careful consideration of the public comments, the EPA is finalizing other aspects of the rulemaking as proposed. For example, the EPA is finalizing the NSPS and EG for process controllers (formerly referred to as pneumatic controllers) as proposed. For both the NSPS and EG, process controllers are required to meet a methane and VOC emission rate of zero. Another area of the rulemaking that the EPA is finalizing as proposed is liquids unloading. These sources are required to comply with best management practices for every well that undergoes liquids unloading that results in vented emissions. The EPA is also finalizing standards for well completions and sweetening units as proposed. See sections X and XI of this preamble for a full summary and rationale of the areas of the rulemaking that are being finalized as proposed.

The EPA conducted an analysis of EJ in the development of this final rulemaking and sought to ensure equitable treatment and meaningful involvement of all people regardless of race, color, national origin, or income in the process. The EPA engaged and consulted representatives of frontline communities that are directly affected by and particularly vulnerable to the climate and health impacts of pollution from this source category through interactions such as webinars, listening sessions, and meetings. These opportunities allowed the EPA to hear directly from the public, especially overburdened and underserved communities, on the development of the rulemaking and to factor these concerns into the rulemaking. The extensive pollution reduction measures in this final rulemaking will collectively reduce the emissions of a suite of harmful pollutants and their associated health impacts in communities adjacent to these emission sources. A full discussion and summary of engagement with pertinent stakeholders can be found in section VII of the preamble. A full discussion of the analysis of EJ is found in section XVI.F of the preamble.

In this final rulemaking, the EPA has conducted a comprehensive analysis of the available data from emission sources in the Crude Oil and Natural Gas source category, the latest available information on control measures and techniques, and information submitted by stakeholders through the public comment process to identify achievable, cost-effective measures to significantly reduce emissions, consistent with the requirements of section 111 of the CAA. This final rulemaking will lead to significant and cost-effective reductions in climate and health-harming pollution and encourage development and deployment of innovative technologies to further reduce this pollution in the Crude Oil and Natural Gas source category.

As described in more detail below, the EPA recognizes that several states and other Federal agencies currently regulate the oil and natural gas industry. The EPA also recognizes that these state and other Federal agency regulatory programs have matured since the EPA began implementing the current NSPS requirements in 2012 and 2016. The EPA further acknowledges the technical innovations that the oil and natural gas industry has made during the past decade; this industry operates at a fast pace and changes constantly as technology evolves. The EPA commends these efforts and recognizes states for their innovative standards, alternative compliance options, and implementation strategies, and these final actions build upon progress made by certain states and Federal agencies in reducing GHG and VOC emissions. See preamble section VI for further discussion of Related State Actions and Other Federal Actions Regulating Oil and Natural Gas Sources and Industry and Voluntary Actions to Address Climate Change.

As the Federal agency with primary responsibility to protect human health and the environment, the EPA has the unique responsibility and authority to regulate harmful air pollutants emitted by the Crude Oil and Natural Gas source category. The EPA recognizes that states and other Federal agencies regulate in accordance with their respective legal authorities and within their respective jurisdictions but collectively do not fully and consistently address the range of sources and emission reduction measures contained in this final rulemaking. Direct Federal regulation of methane from new, reconstructed, and modified sources in this category, combined with approved state plans that are consistent with the EPA's EG presumptive standards for designated facilities (existing sources), will help reduce both climate- and other health-harming pollution from a large number of sources that are either unregulated or from which additional, cost-effective reductions are available, level the regulatory playing field, and help promote technological innovation.

Included in this final rulemaking are the final new subparts NSPS OOOOb and EG OOOOc and amendatory regulatory text for NSPS OOOO, NSPS OOOOa, and 40 CFR part 60, subpart KKK (NSPS KKK). The public docket for this rulemaking also includes the full text redline versions of NSPS OOOO, NSPS OOOOa, and NSPS KKK amendments. In addition, the EPA is providing a Response to Comments (RTC) document and updated documents including the technical support document (TSD), supporting information collection request (ICR) burden statements, and regulatory impact analysis (RIA) that seeks to account for the full impacts of these proposed actions.

B. Summary of the Major Provisions of This Regulatory Action

This final rulemaking includes four distinct groups of actions under the CAA each of which could have been promulgated as a separate final rule. First, pursuant to CAA section 111(b)(1)(B), the EPA has reviewed, and is finalizing revisions to, the standards of performance for the Crude Oil and Natural Gas source category published in 2012 and 2016 and amended in 2020, codified at 40 CFR part 60, subpart OOOO—“Standards of Performance for Crude Oil and Natural Gas Facilities for Which Construction, Modification, or Reconstruction Commenced After August 23, 2011, and on or Before September 18, 2015 ” (2012 NSPS) and subpart OOOOa—“Standards of Performance for Crude Oil and Natural Gas Facilities for which Construction, Modification or Reconstruction Commenced After September 18, 2015” (2016 NSPS OOOOa). Specifically, the EPA is updating, strengthening, and expanding the current requirements under CAA section 111(b) for methane and VOC emissions from sources that commenced construction, modification, or reconstruction after December 6, 2022. These final standards of performance will be in a new subpart, 40 CFR part 60, subpart OOOOb (NSPS OOOOb), and include standards for emission sources previously not regulated under the 2012 NSPS OOOO and 2016 NSPS OOOOa.

Second, pursuant to CAA section 111(d), the EPA is finalizing the first nationwide EG for states to limit methane pollution from designated facilities in the Crude Oil and Natural Gas source category. The EG being finalized in this rulemaking will be in a new subpart, 40 CFR part 60, subpart OOOOc (EG OOOOc). The EG finalizes presumptive standards for GHG emissions (in the form of methane limitations) from designated facilities that commenced construction, reconstruction, or modification on or before December 6, 2022, and implementation requirements designed to inform states in the development, submittal, and implementation of state plans that are required to establish standards of performance for emissions of GHGs from their designated facilities in the Crude Oil and Natural Gas source category. The EPA is also finalizing regulatory language in NSPS OOOO, NSPS OOOOa, and NSPS KKK to provide clarity on when sources transition from being subject to these NSPS and become subject to a state or Federal plan implementing EG OOOOc.

Third, the EPA is taking several related actions stemming from the joint resolution of Congress, adopted on June 30, 2021, under the CRA, disapproving the EPA's final rule titled, “Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources Review,” 85 FR 57018 (September 14, 2020) (“2020 Policy Rule”). As explained in section XII of this document, the EPA is finalizing amendments to the 2016 NSPS OOOOa to address (1) certain inconsistencies between the VOC and methane standards resulting from the disapproval of the 2020 Policy Rule and (2) certain determinations made in the final rule titled, “Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources Reconsideration,” 85 FR 57398 (September 15, 2020) (“2020 Technical Rule”), specifically with respect to fugitive emissions monitoring at low production well sites and gathering and boosting stations. With respect to the latter, as described below, the EPA is finalizing the rescission of provisions of the 2020 Technical Rule that were not supported by the record for that rule or by our subsequent information and analysis.

In addition, in this final rulemaking the EPA updates the NSPS OOOO and NSPS OOOOa provisions in the CFR to reflect the CRA resolution's disapproval of the final 2020 Policy Rule, specifically, the reinstatement of the NSPS OOOO and NSPS OOOOa requirements that the 2020 Policy Rule repealed but that came back into effect immediately upon enactment of the CRA resolution. It should be noted that these requirements have come back into effect already, even prior to these updates to CFR text to reflect them. The EPA waited to make these updates to the CFR text until the final rule simply because it was more efficient and clearer to amend the CFR once at the end of this rulemaking process to account for all changes to the 2012 NSPS OOOO (77 FR 49490, August 16, 2012) and 2016 NSPS OOOOa at the same time.

Fourth, the EPA is finalizing a protocol for the use of OGI in leak detection being finalized as appendix K to 40 CFR part 60 (referred to hereafter as appendix K). While this protocol is being finalized in this action, the applicability of the protocol is broader. The protocol is applicable to facilities when specified in a referencing subpart to help determine the presence and location of leaks; it is not currently applicable for use in direct emission rate measurements from sources. The protocol does not on its own apply to any sources. For NSPS OOOOb and EG OOOOc, we are finalizing the use of the protocol for application at natural gas processing plants. The protocol may be applied to other sources only when incorporated through rulemaking to a specific subpart.

Each group of actions just described is severable from the other. In addition, within each group of actions, the requirements governing each emission source are separate from and so severable from the requirements for each other emission source. Specifically, for each emission source, the EPA separately analyzed and determined the appropriate BSER. And for each emission source, the EPA conducted a separate analysis for new sources governed by the NSPS and for existing sources covered by the EG. Each of the requirements in this final rule is functionally independent— i.e., may operate in practice independently of the other standards of performance.

As CAA section 111(a)(1) requires, the standards of performance being finalized in this rulemaking reflect “the degree of emission limitation achievable through the application of the best system of emission reduction [BSER] which (taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirement) the Administrator determines has been adequately demonstrated.” This rulemaking further finalizes EG for designated facilities, under which states must submit plans which establish standards of performance that reflect the degree of emission limitation achievable through application of the BSER, as identified in the final EG. In this final rulemaking, we evaluated new data made available to the EPA and information provided from public comments on the December 2022 Supplemental Proposal to update the analyses and evaluate whether revisions to the proposed BSER should be considered. For any potential control measure evaluated in this rulemaking, as in the December 2022 Supplemental Proposal, the EPA evaluated the emission reductions achievable through these measures and employed multiple approaches to evaluate the reasonableness of control costs associated with the options under consideration. For example, in evaluating controls for reducing VOC and methane emissions from new sources, we considered a control measure's cost effectiveness under both a “single-pollutant cost effectiveness” approach and a “multipollutant cost effectiveness” approach to appropriately consider that the systems of emission reduction considered in this rulemaking typically achieve reductions in multiple pollutants at once and secure a multiplicity of climate and public health benefits. For both NSPS OOOOb and EG OOOOc, we also compared: (1) the capital costs that would be incurred through compliance with the final standards against the industry's current level of capital expenditures and (2) the annualized costs against the industry's estimated annual revenues. For a detailed discussion of the EPA's consideration of this and other BSER statutory elements, see sections IV and VIII of this preamble. Table 2 summarizes the applicability dates for the four subparts that the EPA is finalizing.

1. New Source Performance Standards for New, Modified, and Reconstructed Sources After December 6, 2022 (NSPS OOOOb)

As described in section X of this preamble, the EPA is finalizing several changes to the BSER and the NSPS for certain affected facilities based on a review of new data made available to the EPA and information provided in public comments. For the other NSPS that generally remain unchanged, the EPA is finalizing them as proposed in the November 2021 Proposal and/or December 2022 Supplemental Proposal. The EPA is also finalizing further justifications, flexibilities, or clarifications, as needed, based on the public comments and other additional information received, as described in section X of this preamble. The NSPS applies to affected sources across the Crude Oil and Natural Gas source category, including the production, processing, transmission, and storage segments, for which construction, reconstruction, or modification commenced after December 6, 2022, which is the date of publication of the supplemental proposal for NSPS OOOOb.

In particular, this action finalizes changes to strengthen the proposed VOC and methane standards addressing: fugitive emissions from well sites; monitoring of control devices; super-emitters; storage vessels; associated gas; pumps; equipment leaks at gas plants; appendix K; centrifugal compressors; and reciprocating compressors. It generally leaves unchanged the SO₂ performance standard for sweetening units and the VOC and methane performance standards for well completions, gas well liquids unloading operations, process controllers, and fugitive emissions from compressor stations. A summary of the final BSER determination and final NSPS for affected sources for which construction, reconstruction, or modification commenced after December 6, 2022 (NSPS OOOOb), is presented in table 2. See sections X and XI of this preamble for a complete discussion of the changes to the BSER determination and NSPS requirements.

The final NSPS OOOOb also includes provisions for the use of advanced methane detection technologies that allow for periodic screening or continuous monitoring for fugitive emissions and emissions from covers and closed vent systems (CVS) used to route emissions to control devices. These advanced methane detection technologies could also be used to identify super-emitter emissions events sooner and outside the normal periodic OGI monitoring for fugitive emissions, control devices, covers on storage vessels, and CVS. Therefore, the EPA is finalizing a Super Emitter Program where an owner or operator must investigate, and if necessary, take steps to ensure compliance with the applicable regulation(s) upon receiving certified notifications of detected emissions that are 100 kilograms per hour (kg/hr) of methane or greater. See section X.C of this preamble for a complete discussion of these final provisions.

2. EG for Sources Constructed Prior to December 6, 2022 (EG OOOOc)

As described in sections X and XI of this preamble, the EPA is finalizing several changes to the BSER determinations and presumptive standards that were proposed under the authority of CAA section 111(d) in the November 2021 Proposal and/or the December 2022 Supplemental Proposal. These changes are based on a review of new data made available to the EPA and information provided in public comments. In the November 2021 Proposal, the EPA proposed the first nationwide EG for GHG (in the form of methane limitations) for the Crude Oil and Natural Gas source category, including the production, processing, and transmission and storage segments (EG OOOOc). In the December 2022 Supplemental Proposal, the EPA proposed key implementation information unique to the EG for stakeholders.

This action finalizes revisions to strengthen the proposed presumptive standards for methane addressing: fugitive emissions from well sites; monitoring of control devices; super-emitters; storage vessels; associated gas; pumps; equipment leaks at gas plants; appendix K; centrifugal compressors; and reciprocating compressors. It generally leaves unchanged the presumptive standards for gas well liquids unloading operations, process controllers, and fugitive emissions from compressor stations. A summary of the final BSER determination and final presumptive standards for EG OOOOc is presented in table 3. See section X of this preamble for a complete discussion of the changes to the BSER determination and final presumptive standards.

The final EG OOOOc also includes the same provisions described for NSPS OOOOb that allow for the use of alternative test methods using advanced methane detection technologies for periodic screening or continuous monitoring for fugitive emissions and emissions from covers and CVS used to route emissions to control devices. Finally, the EPA is also finalizing in the final EG OOOOc presumptive requirements for state plans to include a Super Emitter Program, where an owner or operator must investigate, and if necessary, take steps to ensure compliance with the applicable regulation(s) upon receiving certified notifications of detected emissions that are 100 kilograms per hour (kg/hr) of methane or greater. See section X of this preamble for a complete discussion of these final provisions.

As stated in the November 2021 Proposal and the December 2022 Supplemental Proposal, when the EPA establishes NSPS for a source category, the EPA is required to issue EG to reduce emissions of certain pollutants from existing sources in that same source category. In such circumstances, under CAA section 111(d), the EPA must issue regulations to establish procedures under which states submit plans to establish, implement, and enforce standards of performance for existing sources for certain air pollutants to which a Federal NSPS would apply if such existing source were a new source. Thus, the issuance of CAA section 111(d) final EG does not impose binding requirements directly on existing sources but instead provides requirements for states in developing their plans. There is a fundamental requirement under CAA section 111(d) that a state's standards of performance in its state plan submittal are no less stringent than the presumptive standard determined by the EPA, which derives from the definition of “standard of performance” in CAA section 111(a)(1). Further, as provided in CAA section 111(d), a state may choose to take into account remaining useful life and other factors (RULOF) in applying a standard of performance to a particular source, consistent with the CAA, the EPA's implementing regulations, and the final EG.

The EPA is finalizing changes to the BSER determinations and the degree of limitation achievable through application of the BSER for certain existing equipment, processes, and activities across the Crude Oil and Natural Gas source category. Those changes are discussed in section X of this preamble. Section XIII of this preamble discusses the components of EG, including the steps, requirements, and considerations associated with the development, submittal, and implementation of state, Tribal, and Federal plans, as appropriate. For the EG, the EPA is translating the degree of emission limitation achievable through application of the BSER ( i.e., level of stringency) into presumptive standards that states may use in the development of state plans for specific designated facilities. In doing so, the EPA has formatted the final EG OOOOc such that if a state chooses to adopt these presumptive standards as the standards of performance in a state plan, the EPA could approve such a plan as meeting the requirements of CAA section 111(d) and the finalized EG, if the plan meets all other applicable requirements. In this way, the presumptive standards included in the final EG OOOOc serve a function similar to that of a model rule, because they are intended to assist states in developing their plan submissions by providing states with a starting point for standards that are based on general industry parameters and assumptions. The EPA anticipates that providing these presumptive standards will create a streamlined approach for states in developing state plans and for the EPA in evaluating state plans. However, the EPA's action on each state plan submission is carried out via rulemaking, which includes public notice and comment. Inclusion of presumptive standards in the final EG does not predetermine the outcomes of any future rulemaking on state plan submittals.

Designated facilities located in Indian country would not be encompassed within a state's CAA section 111(d) plan. Instead, an eligible Tribe that has one or more designated facilities located in its area of Indian country would have the opportunity, but not the obligation, to seek authority and submit a plan that establishes standards of performance for those facilities on its Tribal lands. If a Tribe does not submit a plan, or if the EPA does not approve a Tribe's plan, then the EPA has the authority to establish a Federal plan for designated facilities located within that Tribe's area of Indian country. A summary of the final EG for existing sources (EG OOOOc) for the oil and natural gas sector is presented in table 4. See section X of this preamble for a complete discussion of the final EG requirements.

3. Final Amendments to 2016 NSPS OOOOa, and CRA-Related CFR Updates

The EPA is finalizing modifications to the 2016 NSPS OOOOa to address certain amendments to the VOC standards for sources in the production and processing segments finalized in the 2020 Technical Rule. Because the methane standards for the production and processing segments and all standards for the transmission and storage segment were removed from the 2016 NSPS OOOOa via the 2020 Policy Rule prior to the finalization of the 2020 Technical Rule, the latter amendments apply only to the 2016 NSPS OOOOa VOC standards for the production and processing segments. In this final rulemaking, the EPA also is applying some of the 2020 Technical Rule amendments to the methane standards for all industry segments and to VOC standards for the transmission and storage segment in the 2016 NSPS OOOOa. These amendments are associated with the requirements for well completions, pumps, closed vent systems, fugitive emissions, alternative means of emission limitation (AMELs), and onshore natural gas processing plants, as well as other technical clarifications and corrections. The EPA is also finalizing a repeal of the amendments in the 2020 Technical Rule that (1) exempted low production well sites from monitoring fugitive emissions and (2) changed monitoring of VOC emissions at gathering and boosting compressor stations from quarterly to semiannual, which currently applies only to VOC standards (not methane standards) from the production and processing segments. A summary of the final amendments to the 2016 OOOOa NSPS is presented in section XII of this preamble.

Lastly, in this rulemaking, the EPA updates the NSPS OOOO and OOOOa provisions in the CFR to reflect the CRA resolution's disapproval of the final 2020 Policy Rule, specifically, the reinstatement of the NSPS OOOO and OOOOa requirements that the 2020 Policy Rule repealed but that came back into effect immediately upon enactment of the CRA resolution. The EPA waited to make the updates to the CFR text until the final rulemaking because it would be more efficient and clearer to amend the CFR once at the end of this rulemaking process to account for all changes to the 2012 NSPS OOOO and 2016 NSPS OOOOa at the same time, rather than make piecemeal amendments to the CFR.

C. Costs and Benefits

In accordance with the requirements of E.O. 12866, the EPA projected the emissions reductions, costs, and benefits that may result from this final rulemaking. These results are presented in detail in the RIA accompanying this final rulemaking developed in response to E.O. 12866. The RIA focuses on the elements of the final rules that are likely to result in quantifiable cost or emissions changes compared to a baseline without the rule. We estimated the cost, emissions, and benefit impacts for the 2024 to 2038 period. We present the present value (PV) and equivalent annual value (EAV) of costs, benefits, and net benefits of this rulemaking in 2019 dollars.

The initial analysis year in the RIA is 2024 as we assume the NSPS rules will take effect early in 2024. The EG will take longer to go into effect as states will need to develop implementation plans in response to the EG and have them approved by the EPA. We assume in the RIA that this process will take 4 years, and so EG impacts will begin in 2028. The final analysis year is 2038, which allows us to provide up to 15 years of projected impacts after the NSPS is assumed to take effect and 11 years of projected impacts after the EG is assumed to take effect.

The cost analysis presented in the RIA reflects a nationwide engineering analysis of compliance cost and emissions reductions, of which there are two main components. The first component is a set of representative or model plants for each regulated facility, segment, and control option. The characteristics of the model plant include typical equipment, operating characteristics, and representative factors including baseline emissions and the costs, emissions reductions, and product recovery resulting from each control option. The second component is a set of projections of activity data for affected facilities, distinguished by vintage, year, and other necessary attributes ( e.g., oil versus natural gas wells). Impacts are calculated by setting parameters on how and when affected facilities are assumed to respond to a particular regulatory regime, multiplying activity data by model plant cost and emissions estimates, differencing from the baseline scenario, and then summing to the desired level of aggregation. In addition to emissions reductions, some control options result in natural gas recovery, which can then be combusted in production or sold. Where applicable, we present projected compliance costs with and without the projected revenues from product recovery.

The EPA expects climate and health benefits due to the emissions reductions projected under this final rulemaking. The EPA estimated the monetized climate benefits of methane emission reductions expected from these final rules using estimates of the social cost of methane (SC–CH₄) that reflect recent advances in the scientific literature on climate change and its economic impacts and incorporate recommendations made by the National Academies of Science, Engineering, and Medicine (National Academies 2017). The EPA presented these estimates in a sensitivity analysis in the December 2022 RIA, solicited public comment on the methodology and use of these estimates, and has conducted an external peer review of these estimates, as discussed in section XVI.E of this preamble.

In addition to climate benefits from methane emissions reductions, the EPA expects that VOC emission reductions under the final rulemaking will improve air quality and improve health and welfare due to reduced exposure to ozone, particulate matter with a diameter of 2.5 micrometers or less (PM_2.5), and hazardous air pollutants (HAP). In a national-level analysis of public health impacts, the EPA used the environmental Benefits Mapping and Analysis Program—Community Edition (BenMAP–CE) software program to quantify counts of premature deaths and illnesses attributable to photochemical modeled changes in summer season average ozone concentrations resulting from projected VOC emissions reductions under the rulemaking. The methods for quantifying the number and value of air pollution-attributable premature deaths and illnesses are described in the RIA for this action and the TSD titled Estimating PM _2.5 - and Ozone-Attributable Health Benefits. These reductions in health-harming pollution would result in significant public health benefits including avoided premature deaths, reductions in new asthma cases and incidences of asthma symptoms, reductions in hospital admissions and emergency department visits, and reductions in lost school days.

The EPA notes that the benefits analysis is distinct from the statutory BSER determinations finalized herein, which are based on the statutory factors the EPA is required to consider under section 111(a) of the CAA (including cost, energy requirements and nonair quality health, and environmental impacts). The assessment of benefits described above and in the RIA is presented solely for the purposes of complying with E.O. 12866 and providing the public with a complete depiction of the impacts of the rulemaking.

The projected national-level emissions reductions over the 2024 to 2038 period anticipated under the finalized requirements are presented in table 5. Table 6 presents the PV and EAV of the projected benefits, costs, and net benefits over the 2024 to 2038 period under the final rule using discount rates of 2, 3, and 7 percent.

III. Air Emissions From the Crude Oil and Natural Gas Sector and Public Health and Welfare

A. Impacts of GHGs, VOCs, and SO₂ Emissions on Public Health and Welfare

As noted previously, the oil and natural gas industry emits a wide range of pollutants, including GHGs (such as methane and CO₂), VOCs, SO₂, NO_X, H₂ S, CS₂, and COS. See 49 FR 2636, 2637 (January 20, 1984). As noted below, to this point the EPA has focused its regulatory efforts under CAA section 111 on GHGs, VOC, and SO₂ .

1. Climate Change Impacts From GHGs Emissions

Elevated concentrations of GHGs are and have been warming the planet, leading to changes in the Earth's climate including changes in the frequency and intensity of heat waves, precipitation, and extreme weather events; rising seas; and retreating snow and ice. The changes taking place in the atmosphere as a result of the well-documented buildup of GHGs due to human activities are changing the climate at a pace and in a way that threatens human health, society, and the natural environment. Human-produced GHGs, largely derived from our reliance on fossil fuels, are causing serious and life-threatening environmental and health impacts. While the EPA is not making any new scientific or factual findings with regard to the well-documented impact of GHG emissions on public health and welfare in support of this rulemaking, the EPA is providing some scientific background on climate change to offer additional context for this rulemaking and to increase the public's understanding of the environmental impacts of GHGs.

Extensive additional information on climate change is available in the scientific assessments and the EPA documents that are briefly described in this section of this preamble, as well as in the technical and scientific information supporting them. One of those documents is the EPA's 2009 Endangerment and Cause or Contribute Findings for GHGs Under Section 202(a) of the CAA (74 FR 66496, December 15, 2009). In the 2009 Endangerment Findings, the Administrator found under section 202(a) of the CAA that elevated atmospheric concentrations of six key well-mixed GHGs—CO_2, methane, N₂ O, HFCs, perfluorocarbons (PFCs), and sulfur hexafluoride (SF₆)—“may reasonably be anticipated to endanger the public health and welfare of current and future generations” (74 FR 66523, December 15, 2009), and the science and observed changes since that time have confirmed and strengthened the understanding and concerns regarding the climate risks considered in the Findings. The 2009 Endangerment Findings, together with the extensive scientific and technical evidence in the supporting record, documented that climate change caused by human emissions of GHGs threatens the public health of the U.S. population. It explained that by raising average temperatures, climate change increases the likelihood of heat waves, which are associated with increased deaths and illnesses (74 FR 66497, December 15, 2009). While climate change also increases the likelihood of reductions in cold-related mortality, evidence indicates that the increases in heat mortality will be larger than the decreases in cold mortality in the U.S. (74 FR 66525, December 15, 2009). The 2009 Endangerment Findings further explained that compared to a future without climate change, climate change is expected to increase tropospheric ozone pollution over broad areas of the U.S., including in the largest metropolitan areas with the worst tropospheric ozone problems, and thereby increase the risk of adverse effects on public health (74 FR 66525, December 15, 2009). Climate change is also expected to cause more intense hurricanes, and more frequent and intense storms of other types, and heavy precipitation, with impacts on other areas of public health such as the potential for increased deaths, injuries, infectious and waterborne diseases, and stress-related disorders (74 FR 66525, December 15, 2009). Children, the elderly, and the poor are among the most vulnerable to these climate-related health effects (74 FR 66498, December 15, 2009).

The 2009 Endangerment Findings also documented, together with the extensive scientific and technical evidence in the supporting record, that climate change touches nearly every aspect of public welfare in the U.S. with resulting economic costs, including: changes in water supply and quality due to increased frequency of drought and extreme rainfall events; increased risk of storm surge and flooding in coastal areas and land loss due to inundation; increases in peak electricity demand and risks to electricity infrastructure; and the potential for significant agricultural disruptions and crop failures (though offset to some extent by carbon fertilization). These impacts are also global and may exacerbate problems outside the U.S. that raise humanitarian, trade, and national security issues for the U.S. (74 FR 66530, December 15, 2009).

In 2016, the Administrator similarly issued Endangerment and Cause or Contribute Findings for GHG emissions from aircraft under section 231(a)(2)(A) of the CAA (81 FR 54422, August 15, 2016). In the 2016 Endangerment Findings, the Administrator found that the body of scientific evidence amassed in the record for the 2009 Endangerment Findings compellingly supported a similar endangerment finding under CAA section 231(a)(2)(A) and also found that the science assessments released between the 2009 and the 2016 Findings “strengthen and further support the judgment that GHGs in the atmosphere may reasonably be anticipated to endanger the public health and welfare of current and future generations.” (81 FR 54424, August 15, 2016).

Since the 2016 Endangerment Findings, the climate has continued to change, with new records being set for several climate indicators such as global average surface temperatures, GHG concentrations, and sea level rise. Moreover, heavy precipitation events have increased in the eastern U.S. while agricultural and ecological drought has increased in the western U.S. along with more intense and larger wildfires. These and other trends are examples of the risks discussed the 2009 and 2016 Endangerment Findings that have already been experienced. Additionally, major scientific assessments continue to demonstrate advances in our understanding of the climate system and the impacts that GHGs have on public health and welfare both for current and future generations. These updated observations and projections document the rapid rate of current and future climate change both globally and in the U.S. These assessments include:

• U.S. Global Change Research Program's (USGCRP) 2016 Climate and Health Assessment and 2017–2018 Fourth National Climate Assessment (NCA4)

• IPCC's 2018 Global Warming of 1.5 °C, 2019 Climate Change and Land, and the 2019 Ocean and Cryosphere in a Changing Climate assessments, as well as the 2023 IPCC Sixth Assessment Report (AR6).

• The NAS 2016 Attribution of Extreme Weather Events in the Context of Climate Change, 2017 Valuing Climate Damages: Updating Estimation of the Social Cost of Carbon Dioxide, and 2019 Climate Change and Ecosystems assessments.

• National Oceanic and Atmospheric Administration's (NOAA) annual State of the Climate reports published by the Bulletin of the American Meteorological Society, most recently in 2022.

• EPA Climate Change and Social Vulnerability in the United States: A Focus on Six Impacts (2021).

The most recent information demonstrates that the climate is continuing to change in response to the human-induced buildup of GHGs in the atmosphere. These recent assessments show that atmospheric concentrations of GHGs have risen to a level that has no precedent in human history and that they continue to climb, primarily because of both historical and current anthropogenic emissions, and that these elevated concentrations endanger our health by affecting our food and water sources, the air we breathe, the weather we experience, and our interactions with the natural and built environments. For example, atmospheric concentrations of one of these GHGs, CO₂ , measured at Mauna Loa in Hawaii and at other sites around the world reached 419 parts per million (ppm) in 2022 (nearly 50 percent higher than preindustrial levels) and have continued to rise at a rapid rate. Global average temperature has increased by about 1.1 °C (2.0 °F) in the 2011–2020 decade relative to 1850–1900. The years 2015–2021 were the warmest 7 years in the 1880–2021 record, contributing to the warmest decade on record with a decadal temperature of 0.82 °C (1.48 °F) above the 20th century. The IPCC determined (with medium confidence) that this past decade was warmer than any multi-century period in at least the past 100,000 years. Global average sea level has risen by about 8 inches (about 21 centimeters (cm)) from 1901 to 2018, with the rate from 2006 to 2018 (0.15 inches/year or 3.7 millimeters (mm)/year) almost twice the rate over the 1971 to 2006 period, and three times the rate of the 1901 to 2018 period. The rate of sea level rise over the 20th century was higher than in any other century in at least the last 2,800 years. Higher CO₂ concentrations have led to acidification of the surface ocean in recent decades to an extent unusual in the past 2 million years, with negative impacts on marine organisms that use calcium carbonate to build shells or skeletons. Arctic sea ice extent continues to decline in all months of the year; the most rapid reductions occur in September (very likely almost a 13 percent decrease per decade between 1979 and 2018) and are unprecedented in at least 1,000 years. Human-induced climate change has led to heatwaves and heavy precipitation becoming more frequent and more intense, along with increases in agricultural and ecological droughts in many regions.

The assessment literature demonstrates that modest additional amounts of warming may lead to a climate different from anything humans have ever experienced. The 2022 CO₂ concentration of 419 ppm is already higher than at any time in the last 2 million years. If concentrations exceed 450 ppm, they would likely be higher than any time in the past 23 million years: at the current rate of increase of more than 2 ppm a year, this would occur in about 15 years. While GHGs are not the only factor that controls climate, it is illustrative that 3 million years ago (the last time CO₂ concentrations were above 400 ppm) Greenland was not yet completely covered by ice and still supported forests, while 23 million years ago (the last time concentrations were above 450 ppm) the West Antarctic ice sheet was not yet developed, indicating the possibility that high GHG concentrations could lead to a world that looks very different from today and from the conditions in which human civilization has developed. If the Greenland and Antarctic ice sheets were to melt substantially, sea levels would rise dramatically—the IPCC estimated that over the next 2,000 years, sea level will rise by 7 to 10 feet even if warming is limited to 1.5 °C (2.7 °F), from 7 to 20 feet if limited to 2 °C (3.6 °F), and by 60 to 70 feet if warming is allowed to reach 5 °C (9 °F) above preindustrial levels. For context, almost all of the city of Miami is less than 25 feet above sea level, and the NCA4 stated that 13 million Americans would be at risk of migration due to 6 feet of sea level rise. Moreover, the CO₂ being absorbed by the ocean has resulted in changes in ocean chemistry due to acidification of a magnitude not seen in 65 million years, putting many marine species—particularly calcifying species—at risk.

The NCA4 found that it is very likely (greater than 90 percent likelihood) that by mid-century, the Arctic Ocean will be almost entirely free of sea ice by late summer for the first time in about 2 million years. Coral reefs will be at risk for almost complete (99 percent) losses with 1 °C (1.8 °F) of additional warming from today (2 °C or 3.6 °F since preindustrial). At this temperature, between 8 and 18 percent of animal, plant, and insect species could lose over half of the geographic area with suitable climate for their survival, and 7 to 10 percent of rangeland livestock would be projected to be lost. The IPCC similarly found that climate change has caused substantial damages and increasingly irreversible losses in terrestrial, freshwater, and coastal and open ocean marine ecosystems.

Scientific assessments also demonstrate that even modest additional amounts of warming may lead to a climate different from anything humans have ever experienced. Every additional increment of temperature comes with consequences. For example, the half degree of warming from 1.5 to 2 °C (0.9 °F of warming from 2.7 °F to 3.6 °F) above preindustrial temperatures is projected on a global scale to expose 420 million more people to frequent extreme heatwaves, and 62 million more people to frequent exceptional heatwaves (where heatwaves are defined based on a heat wave magnitude index which takes into account duration and intensity—using this index, the 2003 French heat wave that led to almost 15,000 deaths would be classified as an “extreme heatwave” and the 2010 Russian heatwave which led to thousands of deaths and extensive wildfires would be classified as “exceptional”). It would increase the frequency of sea-ice-free Arctic summers from once in 100 years to once in a decade. It could lead to 4 inches of additional sea level rise by the end of the century, exposing an additional 10 million people to risks of inundation as well as increasing the probability of triggering instabilities in either the Greenland or Antarctic ice sheets. Between half a million and a million additional square miles of permafrost would thaw over several centuries. Risks to food security would increase from medium-to-high for several lower-income regions in the Sahel, southern Africa, the Mediterranean, central Europe, and the Amazon. In addition to food security issues, this temperature increase would have implications for human health in terms of increasing ozone concentrations, heatwaves, and vector-borne diseases (for example, expanding the range of the mosquitoes which carry dengue fever, chikungunya, yellow fever, and the Zika virus, or the ticks which carry Lyme, babesiosis, or Rocky Mountain Spotted Fever). Moreover, every additional increment in warming leads to larger changes in extremes, including the potential for events unprecedented in the observational record. Every additional degree will intensify extreme precipitation events by about 7 percent. The peak winds of the most intense tropical cyclones (hurricanes) are projected to increase with warming. In addition to a higher intensity, the IPCC found that precipitation and frequency of rapid intensification of these storms has already increased, the movement speed has decreased, and elevated sea levels have increased coastal flooding, all of which make these tropical cyclones more damaging.

The NCA4 also evaluated a number of impacts specific to the U.S. Severe drought and outbreaks of insects like the mountain pine beetle have killed hundreds of millions of trees in the western U.S. Wildfires have burned more than 3.7 million acres in 14 of the 17 years between 2000 and 2016, and Federal wildfire suppression costs were about a billion dollars annually. The National Interagency Fire Center has documented U.S. wildfires since 1983, and the 10 years with the largest acreage burned have all occurred since 2004. Wildfire smoke degrades air quality, increasing health risks, and more frequent and severe wildfires due to climate change would further diminish air quality, increase incidences of respiratory illness, impair visibility, and disrupt outdoor activities, sometimes thousands of miles from the location of the fire. Meanwhile, sea level rise has amplified coastal flooding and erosion impacts, requiring the installation of costly pump stations, flooding streets, and increasing storm surge damages. Tens of billions of dollars of U.S. real estate could be below sea level by 2050 under some scenarios. Increased frequency and duration of drought will reduce agricultural productivity in some regions, accelerate depletion of water supplies for irrigation, and expand the distribution and incidence of pests and diseases for crops and livestock. The NCA4 also recognized that climate change can increase risks to national security, both through direct impacts on military infrastructure and by affecting factors such as food and water availability that can exacerbate conflict outside U.S. borders. Droughts, floods, storm surges, wildfires, and other extreme events stress nations and people through loss of life, displacement of populations, and impacts on livelihoods.

Ongoing EPA modeling efforts can shed further light on the distribution of climate change damages expected to occur within the U.S. Based on methods from over 30 peer-reviewed climate change impact studies, the EPA's Framework for Evaluating Damages and Impacts (FrEDI) model has developed estimates of the relationship between future temperature changes and physical and economic climate-driven damages occurring in specific U.S. regions for 20 specific impact categories. Recent applications of FrEDI have advanced the collective understanding about how future climate change impacts in these 20 categories are expected to be substantial and distributed unevenly across U.S. regions. Using this framework, the EPA estimates that under a global emission scenario with no additional mitigation, relative to a world with no additional warming since the baseline period (1986–2005), damages accruing to these impact categories in the contiguous U.S. occur mainly through increased deaths due to increasing temperatures as well as climate-driven changes in air quality, transportation impacts due to coastal flooding resulting from sea level rise, increased mortality from wildfire emission exposure and response costs for fire suppression, and reduced labor hours worked in outdoor settings and buildings without air conditioning. The relative damages from long-term climate driven changes in these sectors are also projected to vary from region to region. For example, of the impact categories examined in FrEDI, the largest source of modeled damages differ from region to region, with wildfire impacts in the Northwest, air quality impacts on the East Coast and the Southwest, labor productivity impacts in the Midwest, transportation impacts from high tide flooding in the Southern Plains, and damages to rail infrastructure in the Northern Plains. While the FrEDI framework currently quantifies damages for 20 impact categories within the contiguous U.S., it is important to note that it is still a preliminary and partial assessment of climate impacts relevant to U.S. interests in a number of ways. For example, the FrEDI framework reflects some important health damages from U.S. wildfires ( i.e., mortality and morbidity impacts from wildfire smoke) and suppression costs, but do not yet account for other market and non-market welfare effects of wildfires ( e.g., property damage, impacts to ecosystem services, climate feedback effects from wildfire CO₂ emissions). Similarly, FrEDI models several types of damages from SLR ( e.g., traffic delays due to flooded coastal roadways) but do not reflect others, such as the effect of groundwater intrusion, business interruptions, debris removal costs, or critical infrastructure loss. In addition, FrEDI does not reflect increased damages that occur due to climate-mediated effects to ecosystem services, or national security, interactions between different sectors impacted by climate change or all the ways in which physical impacts of climate change occurring abroad have spillover effects in different regions of the U.S. See the FrEDI Technical Documentation for more details.

Some GHGs also have impacts beyond those mediated through climate change. For example, elevated concentrations of CO₂ stimulate plant growth (which can be positive in the case of beneficial species, but negative in terms of weeds and invasive species, and can also lead to a reduction in plant micronutrients ) and cause ocean acidification. Nitrous oxide depletes the levels of protective stratospheric ozone.

As methane is the primary GHG addressed in this rulemaking, it is relevant to highlight some trends and impacts specific to methane. Concentrations of methane reached 1,912 parts per billion (ppb) in 2022, more than two and a half times the preindustrial concentration of 722 ppb. Moreover, the 2022 concentration was an increase of almost 17 ppb over 2021—the largest annual increase in methane concentrations in the dataset (starting in 1984), continuing a trend of rapid rise since a temporary pause ended in 2007. Methane has a high radiative efficiency—almost 30 times that of CO₂ per ppb (and, therefore, 80 times as much per unit mass). In addition, methane contributes to climate change through chemical reactions in the atmosphere that produce tropospheric ozone and stratospheric water vapor. Human emissions of methane are responsible for about one-third of the warming due to well-mixed GHGs, the second most important human warming agent after CO₂ . Because of the substantial emissions of methane, and its radiative efficiency, methane mitigation is one of the best opportunities for reducing near-term warming.

The tropospheric ozone produced by the reaction of methane in the atmosphere has harmful effects for human health and plant growth in addition to its climate effects. In remote areas, methane is an important precursor to tropospheric ozone formation. Approximately 50 percent of the global annual mean ozone increase since preindustrial times is believed to be due to anthropogenic methane. Projections of future emissions also indicate that methane is likely to be a key contributor to ozone concentrations in the future. Unlike NO_X and VOC, which affect ozone concentrations regionally and at hourly time scales, methane emissions affect ozone concentrations globally and on decadal time scales given methane's long atmospheric lifetime when compared to these other ozone precursors. Reducing methane emissions, therefore, will contribute to efforts to reduce global background ozone concentrations that contribute to the incidence of ozone-related health effects. The benefits of such reductions are global and occur in both urban and rural areas.

These scientific assessments, the EPA analyses, and documented observed changes in the climate of the planet and of the U.S. present clear support regarding the current and future dangers of climate change and the importance of GHG emissions mitigation.

2. VOCs

Many VOCs can be classified as HAP ( e.g., benzene ) and can lead to a variety of health concerns such as cancer and noncancer illnesses ( e.g., respiratory, neurological). Further, VOCs are one of the key precursors in the formation of ozone. Tropospheric, or ground-level, ozone is formed through reactions of VOCs and NO_X in the presence of sunlight. Ozone formation can be controlled to some extent through reductions in emissions of the ozone precursors VOC and NO_X. Recent observational and modeling studies have found that VOC emissions from oil and natural gas operations can impact ozone levels. A significantly expanded body of scientific evidence shows that ozone can cause a number of harmful effects on health and the environment. Exposure to ozone can cause respiratory system effects such as difficulty breathing and airway inflammation. For people with lung diseases such as asthma and chronic obstructive pulmonary disease (COPD), these effects can lead to emergency room visits and hospital admissions. Studies have also found that ozone exposure is likely to cause premature death from lung or heart diseases. In addition, evidence indicates that long-term exposure to ozone is likely to result in harmful respiratory effects, including respiratory symptoms and the development of asthma. People most at risk from breathing air containing ozone include: children; people with asthma and other respiratory diseases; older adults; and people who are active outdoors, especially outdoor workers. An estimated 25.9 million people have asthma in the U.S., including almost 7.1 million children. Asthma disproportionately affects children, families with lower incomes, and minorities, including Puerto Ricans, Native Americans/Alaska Natives, and African Americans.

In the EPA's 2020 Integrated Science Assessment (ISA) for Ozone and Related Photochemical Oxidants, the EPA estimated the incidence of air pollution effects for those health endpoints above where the ISA classified as either causal or likely-to-be-causal. In brief, the ISA for ozone found short-term (less than one month) exposures to ozone to be causally related to respiratory effects, a “likely to be causal” relationship with metabolic effects and a “suggestive of, but not sufficient to infer, a causal relationship” for central nervous system effects, cardiovascular effects, and total mortality. The ISA reported that long-term exposures (one month or longer) to ozone are “likely to be causal” for respiratory effects including respiratory mortality, and a “suggestive of, but not sufficient to infer, a causal relationship” for cardiovascular effects, reproductive effects, central nervous system effects, metabolic effects, and total mortality. An example of quantified incidence of ozone health effects can be found in the Regulatory Impact Analysis for the Final Revised Cross-State Air Pollution Rule (CSAPR) Update.

Scientific evidence also shows that repeated exposure to ozone can reduce growth and have other harmful effects on sensitive plants and trees. These types of effects have the potential to impact ecosystems and the benefits they provide.

3. SO₂

Current scientific evidence links short-term exposures to SO₂, ranging from 5 minutes to 24 hours, with an array of adverse respiratory effects including bronchoconstriction and increased asthma symptoms. These effects are particularly important for asthmatics at elevated ventilation rates ( e.g., while exercising or playing).

Studies also show an association between short-term exposure and increased visits to emergency departments and hospital admissions for respiratory illnesses, particularly in at-risk populations including children, the elderly, and asthmatics.

SO₂ in the air can also damage the leaves of plants, decrease their ability to produce food (photosynthesis), and decrease their growth. In addition to directly affecting plants, SO₂, when deposited on land and in estuaries, lakes, and streams, can acidify sensitive ecosystems resulting in a range of harmful indirect effects on plants, soils, water quality, and fish and wildlife ( e.g., changes in biodiversity and loss of habitat, reduced tree growth, loss of fish species). Sulfur deposition to waterways also plays a causal role in the methylation of mercury.

B. Profile of the Oil and Natural Gas Industry and Its Emissions

This section of the preamble generally describes: the structure of the oil and natural gas industry; the interconnected production, processing, transmission and storage, and distribution segments that move product from well to market; and types of emissions sources in each segment and the industry's emissions.

1. Structure of the Oil and Natural Gas Industry

The EPA characterizes the oil and natural gas industry's operations as being generally composed of four segments: (1) Extraction and production of crude oil and natural gas (“oil and natural gas production”), (2) natural gas processing, (3) natural gas transmission and storage, and (4) natural gas distribution. The EPA regulates oil refineries as a separate source category; accordingly, as with the previous oil and gas NSPS rulemakings, for purposes of this rulemaking, the EPA's focus for crude oil is on operations from the well to the point of custody transfer at a petroleum refinery while the focus for natural gas is on all operations from the well to the local distribution company custody transfer station, commonly referred to as the “city-gate.”

a. Production Segment

The oil and natural gas production segment includes the 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). Although many wells produce a combination of oil and natural gas, wells can generally be grouped into two categories: oil wells and natural gas wells. Oil wells comprise two types, oil wells that produce crude oil only and oil wells that produce both crude oil and natural gas (commonly referred to as “associated” gas). Production equipment and components located on the well pad may include, but are not limited to: wells and related casing heads; tubing heads; “Christmas tree” piping, pumps, and compressors; heater treaters; separators; storage vessels; process controllers; pumps; and dehydrators. Production operations include well drilling, completion, and recompletion processes, including all the portable non-self-propelled apparatuses associated with those operations.

Other sites that are part of the production segment include “centralized tank batteries,” stand-alone sites where oil, condensate, produced water, and natural gas from several wells may be separated, stored, or treated. The production segment also includes gathering pipelines, gathering and boosting compressor stations, and related components that collect and transport the oil, natural gas, and other materials and wastes from the wells to the refineries or natural gas processing plants.

Crude oil and natural gas undergo successive, separate processing. Crude oil is separated from water and other impurities and transported to a refinery via truck, railcar, or pipeline. As noted above, the EPA treats oil refineries as a separate source category; accordingly, for present purposes, the oil component of the production segment ends at the point of custody transfer at the refinery.

The separated, unprocessed natural gas is commonly referred to as field gas and is composed of methane, natural gas liquids (NGL), and other impurities such as water vapor, H₂ S, CO₂, helium, and nitrogen. Ethane, propane, butane, isobutane, and pentane are all considered NGL and often are sold separately for a variety of different uses. Natural gas with high methane content is referred to as “dry gas,” while natural gas with significant amounts of ethane, propane, or butane is referred to as “wet gas.” Natural gas is typically sent to gas processing plants in order to separate NGLs for use as feedstock for petrochemical plants, fuel for space heating and cooking, or a component for blending into vehicle fuel.

b. Processing Segment

The natural gas processing segment consists of separating certain hydrocarbons (HC) and fluids from the natural gas to produce “pipeline quality” dry natural gas. The degree and location of processing is dependent on factors such as the type of natural gas ( e.g., wet or dry gas), market conditions, and company contract specifications. Typically, processing of natural gas begins in the field and continues as the gas is moved from the field through gathering and boosting compressor stations to natural gas processing plants, where the complete processing of natural gas takes place. Natural gas processing operations separate and recover NGL or other non-methane gases and liquids from field gas through one or more of the following processes: oil and condensate separation, water removal, separation of NGL, sulfur and CO₂ removal, fractionation of NGL, and other processes, such as the capture of CO₂ separated from natural gas streams for delivery outside the facility.

c. Transmission and Storage Segment

Once natural gas processing is complete, the resulting natural gas exits the natural gas process plant and enters the transmission and storage segment where it is transmitted to storage and/or distribution to the end user.

Pipelines in the natural gas transmission and storage segment can be interstate pipelines, which carry natural gas across state boundaries, or intrastate pipelines, which transport the gas within a single state. Basic components of the two types of pipelines are the same, though interstate pipelines may be of a larger diameter and operated at a higher pressure. To ensure that the natural gas continues to flow through the pipeline, the natural gas must periodically be compressed, thereby increasing its pressure. Compressor stations perform this function and are usually placed at 40- to 100-mile intervals along the pipeline. At a compressor station, the natural gas enters the station, where it is compressed by reciprocating or centrifugal compressors.

Another part of the transmission and storage segment are aboveground and underground natural gas storage facilities. Storage facilities hold natural gas for use during peak seasons. The main difference between underground and aboveground storage sites is that storage takes place in storage vessels constructed of non-earthen materials in aboveground storage. Underground storage of natural gas typically occurs in depleted natural gas or oil reservoirs and salt dome caverns. One purpose of this storage is for load balancing (equalizing the receipt and delivery of natural gas). At an underground storage site, typically other processes occur, including compression, dehydration, and flow measurement.

d. Distribution Segment

The distribution segment provides the final step in delivering natural gas to customers. The natural gas enters the distribution segment from delivery points located along interstate and intrastate transmission pipelines to business and household customers. The delivery point where the natural gas leaves the transmission and storage segment and enters the distribution segment is a local distribution company's custody transfer station, commonly referred to as the “city-gate.” Natural gas distribution systems consist of over 2 million miles of piping, including mains and service pipelines to the customers. If the distribution network is large, compressor stations may be necessary to maintain flow. However, these stations are typically smaller than transmission compressor stations. Distribution systems include metering stations and regulating stations, which allow distribution companies to monitor the natural gas as it flows through the system.

2. Emissions From the Oil and Natural Gas Source Category

The oil and natural gas industry sector is the largest source of industrial methane emissions in the U.S. Natural gas is composed primarily of methane; every natural gas leak or intentional release through venting or other industrial processes constitutes a release of methane. Methane is a potent GHG; over a 100-year timeframe, it is nearly 30 times more powerful at trapping climate warming heat than CO₂ , and over a 20-year timeframe, it is 83 times more powerful. Because methane is a powerful GHG and is emitted in large quantities, reductions in methane emissions provide a significant benefit in reducing near-term warming. Indeed, one-third of the warming due to GHGs that we are experiencing today is due to human-caused emissions of methane. Additionally, the Crude Oil and Natural Gas sector emits, in varying concentrations and amounts, a wide range of other health-harming pollutants, including VOCs, SO₂, NO_X, H₂ S, CS₂ , and COS. The year 2016 modeling platform produced by the EPA estimated about 3 million tons of VOC are emitted by oil and gas-related sources.

Emissions of methane and these co-pollutants occur in every segment of the Crude Oil and Natural Gas source category, which comprises the oil and natural gas production, natural gas processing, and natural gas transmission and storage segments of the larger industry. Many of the processes and equipment types that contribute to these emissions are found in every segment of the source category and are highly similar across segments. Emissions from the crude oil portion of the regulated source category result primarily from field production operations, such as venting of associated gas from oil wells, oil storage vessels, and production-related equipment such as gas dehydrators, pig traps, process controllers, and pumps. Emissions from the natural gas portion of the industry can occur in all segments. As natural gas moves through the system, emissions primarily result from intentional venting through normal operations, routine maintenance, unintentional fugitive emissions, flaring, malfunctions, and system upsets. Venting can occur through equipment design or operational practices, such as the continuous bleed and intermittent venting of gas from process controllers (devices that control gas flows, levels, temperatures, and pressures in the equipment). In addition to vented emissions, emissions can occur from leaking equipment (also referred to as fugitive emissions) in all parts of the infrastructure, including major production and processing equipment ( e.g., separators or storage vessels) and individual components ( e.g., valves or connectors). Flares are commonly used throughout each segment in the oil and natural gas industry as a control device—to provide pressure relief to prevent risk of explosions; to destroy methane, which has a high global warming potential, and convert it to CO₂ which has a lower global warming potential; and to control other air pollutants such as VOC.

“Super-emitting” events, sites, or equipment, which refer to a small proportion of particularly highly emitting sources that account for a large proportion of overall emissions, can occur throughout the oil and natural gas industry and have been observed in the equipment types and activities covered by this final rulemaking. There are a number of definitions for the term “super-emitter.” A 2018 National Academies of Sciences, Engineering, and Medicine report on methane discussed three categories of “high-emitting” sources:

• Routine or “chronic” high-emitting sources, which regularly emit at higher rates relative to “peers” in a sample. Examples include large facilities and large emissions at smaller facilities caused by poor design or operational practices.
• Episodic high-emitting sources, which are typically large in nature and are generally intentional releases from known maintenance events at a facility. Examples include gas well liquids unloading, well workovers and maintenance activities, and compressor station or pipeline blowdowns.

• Malfunctioning high-emitting sources, which can be either intermittent or prolonged in nature and result from malfunctions and poor work practices. Examples include malfunctioning intermittent process controllers and stuck open dump valves. Another example is well blowout events. For example, a 2018 well blowout in Ohio was estimated to have emitted over 60,000 tons of methane.

Super-emitters have been observed at many different scales, from site-level to component-level, across many research studies. Studies will often develop a study-specific definition such as a top percentile of emissions in a study population ( e.g., top 10 percent), emissions exceeding a certain threshold ( e.g., 26 kg/day), emissions over a certain detection threshold ( e.g., 1–3 g/s) or as facilities with the highest proportional emission rate. For certain equipment types and activities, the EPA's GHG emission estimates include the full range of conditions, including “super-emitters.” For other situations, where data are available, emissions estimates for abnormal events are calculated separately and included in the Inventory of U.S. Greenhouse Gas Emissions and Sinks (GHGI) ( e.g., Aliso Canyon leak event). Given the variability of practices and technologies across oil and gas systems and the occurrence of episodic events, it is possible that the EPA's estimates do not include all methane emissions from abnormal events. The EPA continues to engage with the research community and expert stakeholders to review new data from the EPA's Greenhouse Gas Reporting Program (GHGRP) petroleum and natural gas systems source category (40 CFR part 98, subpart W, also referred to as “GHGRP subpart W”), as well as the peer-reviewed scientific literature and research studies to assess how emissions estimates can be improved. Because lost gas, whether through fugitive emissions, unintentional gas carry-through, or intentional releases, represents lost earning potential, the industry benefits from capturing and selling emissions of natural gas (and methane). Limiting super-emitters through actions included in this rulemaking such as reducing fugitive emissions, using lower emitting equipment where feasible, and employing best management practices will not only reduce emissions but reduce the loss of revenue from this valuable commodity.

Below we provide estimated emissions of methane, VOC, and SO₂ from oil and natural gas industry operation sources.

a. Methane Emissions in the U.S. and From the Oil and Natural Gas Industry

Official U.S. estimates of national-level GHG emissions and sinks are developed by the EPA for the GHGI in fulfillment of commitments under the United Nations Framework Convention on Climate Change. The GHGI, which includes recent trends, is organized by industrial sector. The oil and natural gas production, natural gas processing, and natural gas transmission and storage sectors emit 28 percent of U.S. anthropogenic methane. Table 7 presents total U.S. anthropogenic methane emissions for the years 1990, 2010, and 2021.

In accordance with the practice of the EPA GHGI, the EPA GHGRP, and international reporting standards under the U.N. Framework Convention on Climate Change, the 2007 IPCC Fourth Assessment Report value of the methane 100-year GWP is used for weighting emissions in the following tables. The 100-year GWP value of 28 for methane indicates that 1 ton of methane has approximately as much climate impact over a 100-year period as 28 tons of CO₂ . The most recent IPCC AR6 assessment has calculated updated 100-year GWPs for methane of either 27.2 or 29.8 depending on whether the value includes the CO₂ produced by the oxidation of methane in the atmosphere. As mentioned earlier, because methane has a shorter lifetime than CO₂, the emissions of a ton of methane will have more impact earlier in the 100-year timespan and less impact later in the 100-year timespan relative to the emissions of a 100-year GWP-equivalent quantity of CO₂: when using the AR6 20-year GWP of 81, which only looks at impacts over the next 20 years, the total U.S. emissions of methane in 2021 would be equivalent to about 2,140 MMT CO₂.

Table 8 presents total methane emissions from natural gas production through transmission and storage and petroleum production, for years 1990, 2010, and 2021, in MMT CO₂ Eq. (or million metric tons CO₂ Eq.) of methane.

b. Global GHG Emissions

For additional background information and context, we used 2018 World Resources Institute Climate Watch data to make comparisons between U.S. oil and natural gas production and natural gas processing and transmission and storage emissions and the emissions inventories of entire countries and regions. The U.S. methane emissions from oil and natural gas production and natural gas processing and transmission and storage constitute 0.4 percent of total global emissions of all GHGs (48,600 MMT CO₂ Eq.) from all sources.¹⁰³ Ranking U.S. emissions of methane from oil and natural gas production and natural gas processing and transmission and storage against total GHG emissions for entire countries (using 2021 Climate Watch data) shows that these emissions are comparatively large as they exceed the national-level emissions totals for all GHGs and all anthropogenic sources for Colombia, the Czech Republic, Chile, Belgium, and over 164 other countries. This means that the U.S. emits more of a single GHG—methane—from a single sector—the oil and natural gas sector—than the total combined GHGs emitted by 168 countries. Furthermore, U.S. emissions of methane from oil and natural gas production and natural gas processing and transmission and storage are greater than the sum of total emissions of 63 of the lowest-emitting countries and territories using the 2021 Climate Watch data set.

As illustrated by the domestic and global GHGs comparison data summarized above, the collective GHG emissions from the Crude Oil and Natural Gas source category are significant, whether the comparison is domestic (where this sector is the largest source of methane emissions, accounting for 28 percent of U.S. methane and 3 percent of total U.S. emissions of all GHGs), global (where this sector, accounting for 0.4 percent of all global GHG emissions, emits more than the total national emissions of over 160 countries, and combined emissions of over 60 countries), or when both the domestic and global GHG emissions comparisons are viewed in combination. Consideration of the global context is important. GHG emissions from U.S. oil and natural gas production and natural gas processing and transmission and storage will become globally well-mixed in the atmosphere and thus will have an effect on both the U.S. regional and global climate for years and indeed many decades to come. No single GHG source category dominates on the global scale. While the Crude Oil and Natural Gas source category, like many (if not all) individual GHG source categories, could appear small in comparison to total emissions, in fact, it is a very important contributor both in terms of absolute emissions and in comparison to other source categories globally or within the U.S.

The IPCC AR6 assessment determined that “[f]rom a physical science perspective, limiting human-induced global warming to a specific level requires limiting cumulative CO₂ emissions, reaching at least net zero CO₂ emissions, along with strong reductions in other GHG emissions.” The report also singled out the importance of “strong and sustained methane emission reductions” in part due to the short lifetime of methane leading to the near-term cooling from reductions in methane emissions, which can offset the warming that will result due to reductions in emissions of cooling aerosols such as SO₂. Therefore, reducing methane emissions globally is an important facet in any strategy to limit warming. In the oil and gas sector, methane reductions are highly achievable and cost-effective using existing and well-known solutions and technologies that actually result in recovery of saleable product.

c. VOC and SO₂ Emissions in the U.S. and From the Oil and Natural Gas Industry

Official U.S. estimates of national-level VOC and SO₂ emissions are developed by the EPA for the National Emissions Inventory (NEI), for which states are required to submit information under 40 CFR part 51, subpart A. Data in the NEI may be organized by various data categories, including sector, NAICS code, and Source Classification Code. Tables 9 and 10 below present total U.S. VOC and SO₂ emissions by sector, respectively, for the year 2020, in kilotons (kt) (or thousand metric tons). The oil and natural gas sector represents the top anthropogenic U.S. sector for VOC emissions after removing the biogenics and wildfire sectors in table 9 (about 23 percent of the total VOC emitting by anthropogenic sources). About 10 percent of the total U.S. anthropogenic SO₂ comes from the oil and natural gas sector.

Table 11 presents total VOC and SO₂ emissions from oil and natural gas production through transmission and storage, for the year 2020, in kt. The contribution to the total anthropogenic VOC emissions budget from the oil and gas sector has been increasing in recent NEI cycles. In the 2020 NEI, the oil and gas sector makes up about 23 percent of the total VOC emissions from anthropogenic sources. The SO₂ emissions have been declining in almost every anthropogenic sector, but the oil and gas sector is an exception where SO₂ emissions have been increasing in recent years.

IV. Statutory Background and Regulatory History

A. Statutory Background of CAA Sections 111(b), 111(d), and General Implementing Regulations

The EPA's authority for this rulemaking is CAA section 111, which governs the establishment of standards of performance for stationary sources. This CAA section requires the EPA to list source categories to be regulated, establish standards of performance for air pollutants emitted by new sources in that source category, and establish EG for states to establish standards of performance for certain pollutants emitted by existing sources in that source category.

Specifically, CAA section 111(b)(1)(A) requires that a source category be included on the list for regulation if, “in [the EPA Administrator's] judgment it causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare.” This determination is commonly referred to as an “endangerment finding” and that phrase encompasses both the “causes or contributes significantly to” component and the “endanger public health or welfare” component of the determination. Once a source category is listed, CAA section 111(b)(1)(B) requires that the EPA propose and then promulgate “standards of performance” for new sources in such source category. CAA section 111(a)(1) defines a “standard of performance” as “a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated.” As long recognized by the D.C. Circuit, “[b]ecause Congress did not assign the specific weight the Administrator should accord each of these factors, the Administrator is free to exercise his discretion in this area.” New York v. Reilly, 969 F.2d 1147, 1150 (D.C. Cir. 1992). See also Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 1999) (“ Lignite Energy Council”) (“Because section 111 does not set forth the weight that be [sic] should assigned to each of these factors, we have granted the Agency a great degree of discretion in balancing them”).

In determining whether a given system of emission reduction qualifies as “the best system of emission reduction . . . adequately demonstrated,” or “BSER,” CAA section 111(a)(1) requires that the EPA take into account, among other factors, “the cost of achieving such reduction.” As described in the proposal for the 2016 Rule and in the November 2021 Proposal for this rulemaking, the U.S. Court of Appeals for the District of Columbia Circuit (the D.C. Circuit) has stated that in light of this provision, the EPA may not adopt a standard the cost of which would be “exorbitant,” “greater than the industry could bear and survive,” “excessive,” or “unreasonable.” These formulations appear to be synonymous, and for convenience, in this rulemaking, as in previous rulemakings, we will refer to this standard as reasonableness, so that a control technology may be considered the “best system of emission reduction . . . adequately demonstrated” if its costs are reasonable, but cannot be considered the BSER if its costs are unreasonable. See 80 FR 64662, 64720–21 (October 23, 2015).

CAA section 111(a) does not provide specific direction regarding what metric or metrics to use in considering costs, affording the EPA considerable discretion in choosing a means of cost consideration. In this rulemaking, we evaluated whether a control cost is reasonable under a number of approaches that we find appropriate for assessing the types of controls at issue. For example, we evaluated costs at a sector level by assessing the projected new capital expenditures required under the final rulemaking (compared to overall new capital expenditures by the sector) and the projected compliance costs (compared to overall annual revenue for the sector) if the rule were to require such controls. In evaluating controls for reducing VOC and methane emissions from new sources, we also considered a control's cost effectiveness under both a “single-pollutant cost effectiveness” approach and a “multipollutant cost effectiveness” approach, in order to appropriately take into account that the systems of emission reduction considered in this rule typically achieve reductions in multiple pollutants at once and secure a multiplicity of climate and public health benefits. For a detailed discussion of these cost approaches, please see section VIII.B of the preamble as well as the November 2021 Proposal and the December 2022 Supplemental Proposal.

Under CAA section 111(a)(1), an essential, although not sufficient, condition for a “system of emission reduction” to serve as the basis for an “achievable” emission limitation is that the Administrator must determine that the system is “adequately demonstrated.” This means, according to the D.C. Circuit, that the system is “one which has been shown to be reasonably reliable, reasonably efficient, and which can reasonably be expected to serve the interests of pollution control without becoming exorbitantly costly in an economic or environmental way.” It does not mean that the system “must be in actual routine use somewhere,” though the technologies relied upon in this final rulemaking are. Similarly, the EPA may “hold the industry to a standard of improved design and operational advances, so long as there is substantial evidence that such improvements are feasible.” Ultimately, the analysis “is partially dependent on `lead time,'” that is, “the time in which the technology will have to be available.” The caselaw is clear that the EPA may treat a set of control measures as “adequately demonstrated” regardless of whether the measures are in widespread commercial use. For example, the D.C. Circuit upheld the EPA's determination that selective catalytic reduction (SCR) was adequately demonstrated to reduce NO<sub>X</sub> emissions from coal-fired industrial boilers, even though it was a “new technology.” The court explained that “section 111 `looks toward what may fairly be projected for the regulated future, rather than the state of the art at present.' ” The court added that the EPA may determine that control measures are “adequately demonstrated” through a “reasonable extrapolation of [the control measures'] performance in other industries.”

As defined in CAA section 111(a), the “standard of performance” that the EPA develops, based on the BSER, is expressed as a performance level (typically, a rate-based standard). CAA section 111(b)(5) precludes the EPA from prescribing a particular technological system that must be used to comply with a standard of performance. Rather, sources can select any measure or combination of measures that will achieve the standard.

CAA section 111(h)(1) authorizes the Administrator to promulgate “a design, equipment, work practice, or operational standard, or combination thereof” if in his or her judgment, “it is not feasible to prescribe or enforce a standard of performance.” CAA section 111(h)(2) provides the circumstances under which prescribing or enforcing a standard of performance is “not feasible,” such as when the pollutant cannot be emitted through a conveyance designed to emit or capture the pollutant, or when there is no practicable measurement methodology for the particular class of sources. CAA section 111(b)(1)(B) requires the EPA to “at least every 8 years review and, if appropriate, revise” performance standards unless the “Administrator determines that such review is not appropriate in light of readily available information on the efficacy” of the standard.

As mentioned above, once the EPA lists a source category under CAA section 111(b)(1)(A), CAA section 111(b)(1)(B) provides the EPA discretion to determine the pollutants and sources to be regulated. In addition, concurrent with the 8-year review (and though not a mandatory part of the 8-year review), the EPA may examine whether to add standards for pollutants or emission sources not currently regulated for that source category.

Once the EPA establishes NSPS in a particular source category, the EPA is required in certain circumstances to issue EG to reduce emissions from existing sources in that same source category. Specifically, CAA section 111(d) requires that the EPA prescribe regulations to establish procedures under which states submit plans to establish, implement, and enforce standards of performance for existing sources for certain air pollutants to which a Federal NSPS would apply if such existing source were a new source. The EPA addresses this CAA requirement both through its promulgation of general implementing regulations for CAA section 111(d) as well as through specific EG. The EPA first published general implementing regulations in 1975, 40 FR 53340 (November 17, 1975) (codified at 40 CFR part 60, subpart B), and has revised its CAA section 111(d) implementing regulations several times. on the EPA published updated implementing regulations in 2019, 84 FR 32520 (codified at 40 CFR part 60, subpart Ba), which apply to EG promulgated after July 8, 2019, 40 CFR 60.20a(a), including this EG, and which were recently revised. In accordance with CAA section 111(d), states are required to submit plans pursuant to these regulations to establish standards of performance for existing sources for any air pollutant: (1) the emission of which is subject to a Federal NSPS; and (2) which is neither a pollutant regulated under CAA section 108(a) ( i.e., criteria pollutants such as ground-level ozone and particulate matter (PM), and their precursors, like VOC) nor a HAP regulated under CAA section 112. See also definition of “designated pollutant” in 40 CFR 60.21a(a). The EPA's general implementing regulations use the term “designated facility” to identify those existing sources that may be subject to regulation under the provision of CAA section 111(d). See 40 CFR 60.21a(b).

While states are authorized to establish standards of performance for designated facilities, there is a fundamental requirement under CAA section 111(d) that a state's standards of performance in its state plan submittal are no less stringent than the presumptive standard determined by the EPA, which derives from the definition of “standard of performance” in CAA section 111(a)(1). The EPA identifies the degree of emission limitation achievable through application of the BSER as part of its EG. See 40 CFR 60.22a(b)(5). While standards of performance must generally reflect the degree of emission limitation achievable through application of the BSER, CAA section 111(d)(1) also requires that the EPA regulations permit the states, in applying a standard of performance to a particular source, to take into account the source's RULOF. States may apply less stringent standards of performance to particular sources based on consideration of such sources' remaining useful life and other factors.

After the EPA issues final EG per the requirements under CAA section 111(d) and under 40 CFR part 60, subpart Ba, states are required to submit to the EPA plans that establish standards of performance for the designated facilities as defined in the EPA's guidelines and that contain other measures to implement and enforce those standards. The EPA's final EG issued under CAA section 111(d) do not impose binding requirements directly on sources but instead provide requirements for states in developing their plans and criteria for assisting the EPA when judging the adequacy of such plans. Under CAA section 111(d), and the EPA's implementing regulations, a state must submit its plan to the EPA for approval; the EPA will evaluate the plan for completeness in accordance with enumerated criteria and then will act on that plan via a rulemaking process to either approve or disapprove the plan in whole or in part. If a state does not submit a plan, or if the EPA does not approve a state's plan because it is not “satisfactory,” then the EPA must establish a Federal plan for designated facilities in that state. If the EPA approves a state's plan, the provisions in the state plan become federally enforceable against the designated facility responsible for compliance in the same manner as the provisions of an approved State Implementation Plan (SIP) under CAA section 110. If no designated facility is located within a state, the state must submit to the EPA a letter certifying to that effect in lieu of submitting a state plan. See 40 CFR 60.23a(b).

Designated facilities located in Indian country would not be addressed by a state's CAA section 111(d) plan. Instead, an eligible Tribe that has one or more designated facilities located in its area of Indian country would have the opportunity, but not the obligation, to seek authority and submit a plan that establishes standards of performance for those facilities on its Tribal lands. If a Tribe does not submit a plan, or if the EPA does not approve a Tribe's plan, then the EPA has the authority to establish a Federal plan for the designated facilities located on its Tribal land.

B. What is the regulatory history and litigation background of NSPS and EG for the oil and natural gas industry?

1. 1979 Listing of Source Category

Subsequent to the enactment of the CAA of 1970, the EPA took action to develop standards of performance for new stationary sources as directed by Congress in CAA section 111. By 1977, the EPA had promulgated NSPS for a total of 27 source categories, while NSPS for an additional 25 source categories were then under development. However, in amending the CAA that year, Congress expressed dissatisfaction that the EPA's pace was too slow. Accordingly, the 1977 CAA Amendments included a new subsection (f) in section 111, which specified a schedule for the EPA to list additional source categories under CAA section 111(b)(1)(A) and prioritize them for regulation under CAA section 111(b)(1)(B).

In 1979, as required by CAA section 111(f), the EPA published a list of source categories, which included “ Crude Oil and Natural Gas Production,” for which the EPA would promulgate standards of performance under CAA section 111(b). See “Priority List and Additions to the List of Categories of Stationary Sources,” 44 FR 49222 (August 21, 1979) (“1979 Priority List”). That list included, in the order of priority for promulgating standards, source categories that the EPA Administrator had determined, pursuant to CAA section 111(b)(1)(A), contribute significantly to air pollution that may reasonably be anticipated to endanger public health or welfare. See 44 FR 49223 (August 21, 1979); see also 49 FR 2636–37 (January 20, 1984).

2. 1985 NSPS for VOC and SO₂ Emissions From Natural Gas Processing Plants

On June 24, 1985 (50 FR 26122), the EPA promulgated NSPS for the Crude Oil and Natural Gas source category that addressed VOC emissions from equipment leaks at onshore natural gas processing plants (40 CFR part 60, subpart KKK). On October 1, 1985 (50 FR 40158), the EPA promulgated additional NSPS for the source category to regulate SO₂ emissions from onshore natural gas processing plants (40 CFR part 60, subpart LLL).

3. 2012 NSPS OOOO Rule and Related Amendments

In 2012, pursuant to its duty under CAA section 111(b)(1)(B) to review and, if appropriate, revise the 1985 NSPS, the EPA published the final rule, “Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution,” 77 FR 49490 (August 16, 2012) (40 CFR part 60, subpart OOOO) (“2012 NSPS OOOO”). The 2012 rule updated the SO₂ standards for sweetening units and the VOC standards for equipment leaks at onshore natural gas processing plants. In addition, it established VOC standards for several oil and natural gas-related operations emission sources not covered by 40 CFR part 60, subparts KKK and LLL, including natural gas well completions, centrifugal and reciprocating compressors, certain natural gas-driven process controllers in the production and processing segments of the industry, and storage vessels in the production, processing, and transmission and storage segments.

In 2013, 2014, and 2015 the EPA amended the 2012 NSPS OOOO rule in order to address implementation of the standards. “Oil and Natural Gas Sector: Reconsideration of Certain Provisions of New Source Performance Standards,” 78 FR 58416 (September 23, 2013) (“2013 NSPS OOOO”) (concerning storage vessel implementation); “Oil and Natural Gas Sector: Reconsideration of Additional Provisions of New Source Performance Standards,” 79 FR 79018 (December 31, 2014) (“2014 NSPS OOOO”) (concerning well completion); “Oil and Natural Gas Sector: Definitions of Low Pressure Gas Well and Storage Vessel,” 80 FR 48262 (August 12, 2015) (“2015 NSPS OOOO”) (concerning low-pressure gas wells and storage vessels).

The EPA received petitions for both judicial review and administrative reconsiderations for the 2012, 2013, and 2014 NSPS OOOO rules. The EPA denied reconsideration for some issues, see “Reconsideration of the Oil and Natural Gas Sector: New Source Performance Standards; Final Action,” 81 FR 52778 (August 10, 2016), and, as noted below, granted reconsideration for other issues. As explained below, all litigation related to NSPS OOOO is currently in abeyance.

4. 2016 NSPS OOOOa Rule and Related Amendments

a. Regulatory Action

On June 3, 2016, the EPA published a final rule titled, “Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources; Final Rule,” at 81 FR 35824 (40 CFR part 60, subpart OOOOa) (“2016 Rule” or “2016 NSPS OOOOa”). The 2016 NSPS OOOOa rule established NSPS for sources of GHGs and VOC emissions for certain equipment, processes, and operations across the oil and natural gas industry, including in the transmission and storage segment (81 FR 35832). The EPA explained that the 1979 listing identified the source category broadly enough to include that segment and, in the alternative, if the listing had limited the source category to the production and processing segments, the EPA affirmatively expanded the source category to include the transmission and storage segment on grounds that operations in those segments are a sequence of functions that are interrelated and necessary for getting the recovered gas ready for distribution (81 FR 35832). In addition, because the 2016 rule represented the first time that the EPA had promulgated NSPS for GHG emissions from the Crude Oil and Natural Gas source category, the EPA predicated those NSPS on a determination that it had a rational basis on which to regulate GHG emissions from the source category (81 FR 35843). In response to comments, the EPA explained that it was not required to make an additional pollutant-specific finding that GHG emissions from the source category contribute significantly to dangerous air pollution, but in the alternative, the EPA did make such a finding, relying on the same information that it relied on when determining that it had a rational basis on which to promulgate a GHG NSPS (81 FR 35843).

Specifically, the 2016 NSPS OOOOa addresses the following emission sources:

• Sources that were unregulated under the 2012 NSPS OOOO (hydraulically fractured oil well completions, pneumatic pumps, and fugitive emissions from well sites and compressor stations);
• Sources that were regulated under the 2012 NSPS OOOO for VOC emissions, but not for GHG emissions (hydraulically fractured gas well completions and equipment leaks at natural gas processing plants); and
• Certain equipment that is used across the source category, of which the 2012 NSPS OOOO regulated emissions of VOC from only a subset (process controllers, centrifugal compressors, and reciprocating compressors, with the exception of those compressors located at well sites).

On March 12, 2018 (83 FR 10628), the EPA finalized amendments to certain aspects of the 2016 NSPS OOOOa requirements for the collection of fugitive emissions components at well sites and compressor stations, specifically (1) the requirement that components on a delay of repair must conduct repairs during unscheduled or emergency vent blowdowns, and (2) the monitoring survey requirements for well sites located on the Alaska North Slope.

b. Petitions for Judicial Review and To Reconsider

Following promulgation of the 2016 NSPS OOOOa rule, several states and industry associations challenged the final rule in the D.C. Circuit. The Administrator also received five petitions for reconsideration of several provisions of the final rule. Copies of the petitions are posted in Docket ID No. EPA–HQ–OAR–2010–0505. As noted below, the EPA granted reconsideration as to several issues raised with respect to the 2016 NSPS OOOOa rule and finalized certain modifications discussed in the next section of this document. As explained in the next section, all litigation challenging the 2016 NSPS OOOOa rule is currently stayed.

5. 2020 Policy and Technical Rules

a. Regulatory Action

In September 2020, the EPA published two final rules to amend 2012 NSPS OOOO and 2016 NSPS OOOOa. The first is titled, “Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources Review.” 85 FR 57018 (September 14, 2020). Commonly referred to as the 2020 Policy Rule, it first rescinded the regulations applicable to the transmission and storage segment on the basis that the 1979 listing limited the source category to the production and processing segments and that the transmission and storage segment is not “sufficiently related” to the production and processing segments and therefore cannot be part of the same source category (85 FR 57027, 57029). In addition, the 2020 Policy Rule rescinded methane requirements for the industry's production and processing segments on two separate bases. The first was that such standards are redundant to VOC standards for these segments (85 FR 57030). The second was that the rule interpreted CAA section 111 to require, or at least authorize the Administrator to require, a pollutant-specific “significant contribution finding” (SCF) as a prerequisite to a NSPS for a pollutant, and to require that such finding be supported by some identified standard or established set of criteria for determining which contributions are “significant” (85 FR 57034). The 2020 Policy Rule went on to conclude that the alternative significant-contribution finding that the EPA made in the 2016 Rule for GHG emissions was flawed because it accounted for emissions from the transmission and storage segment and because it was not supported by criteria or a threshold (85 FR 57038).

Published on September 15, 2020, the second of the two rules is titled, “Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources Reconsideration.” Commonly referred to as the 2020 Technical Rule, this second rule made further amendments to the 2016 NSPS OOOOa following the 2020 Policy Rule to eliminate or reduce certain monitoring obligations and to address a range of issues in response to administrative petitions for reconsideration and other technical and implementation issues brought to the EPA's attention since the 2016 NSPS OOOOa rulemaking. Specifically, the 2020 Technical Rule exempted low production well sites from fugitives monitoring (previously required semiannually), required semiannual monitoring at gathering and boosting compressor stations (previously quarterly), streamlined recordkeeping and reporting requirements, allowed compliance with certain equivalent state requirements as an alternative to NSPS fugitive requirements, streamlined the application process to request the use of new technologies to monitor for fugitive emissions, addressed storage tank batteries for applicability determination purposes and finalized several technical corrections. Because the 2020 Technical Rule was issued the day after the EPA's rescission of methane regulations in the 2020 Policy Rule, the amendments made in the 2020 Technical Rule applied only to the requirements to regulate VOC emissions from this source category. The 2020 Policy Rule amended 40 CFR part 60, subparts OOOO and OOOOa, as finalized in 2016. The 2020 Technical Rule amended the 40 CFR part 60, subpart OOOOa, as amended by the 2020 Policy Rule.

b. Petitions To Reconsider

The EPA received three petitions for reconsideration of the 2020 rulemakings. Two of the petitions sought reconsideration of the 2020 Policy Rule. As discussed below, on June 30, 2021, the President signed into law S.J. Res. 14, a joint resolution under the CRA disapproving the 2020 Policy Rule, and as a result, the petitions for reconsideration on the 2020 Policy Rule are now moot. All three petitions sought reconsideration of certain elements of the 2020 Technical Rule.

c. Litigation

Several states and non-governmental organizations (NGOs) challenged the 2020 Policy Rule as well as the 2020 Technical Rule. All petitions for review regarding the 2020 Policy Rule were consolidated into one case in the D.C. Circuit. State of California, et al. v. EPA, No. 20–1357. On August 25, 2021, after the enactment of the joint resolution of Congress disapproving the 2020 Policy Rule (explained in section VIII of this preamble), the U.S. Court of Appeals for the District of Columbia Circuit ( i.e., the court) granted petitioners' motion to voluntarily dismiss their cases. Id. ECF Docket #1911437. All petitions for review regarding the 2020 Technical Rule were consolidated into a different case in the D.C. Circuit. Environmental Defense Fund (EDF), et al. v. EPA, No. 20–1360 (D.C. Cir.). On February 19, 2021, the court issued an order granting a motion by the EPA to hold in abeyance the consolidated litigation over the 2020 Technical Rule pending the EPA's rulemaking actions in response to E.O. 13990 and pending the conclusion of the EPA's potential reconsideration of the 2020 Technical Rule. Id. ECF Docket #1886335.

As mentioned above, the EPA received petitions for judicial review regarding the 2012, 2013, and 2014 NSPS OOOO rules as well as the 2016 NSPS OOOOa rule. The challenges to the 2012 NSPS OOOO rule (as amended by the 2013 NSPS OOOO and 2014 NSPS OOOO rules) were consolidated. American Petroleum Institute v. EPA, No. 13–1108 (D.C. Cir.). The majority of those cases were further consolidated with the consolidated challenges to the 2016 NSPS OOOOa rule. West Virginia v. EPA, No. 16–1264 (D.C. Cir.), see specifically ECF Docket #1654072. As such, West Virginia v. EPA includes challenges to the 2012 NSPS OOOO rule (as amended by the 2013 NSPS OOOO and 2014 NSPS OOOO rules) as well as challenges to the 2016 NSPS OOOOa rule. On December 10, 2020, the court granted a joint motion of the parties in West Virginia v. EPA to hold that case in abeyance until after the mandate has issued in the case regarding challenges to the 2020 Technical Rule. West Virginia v. EPA, ECF Docket #1875192.

C. Congressional Review Act (CRA) Joint Resolution of Disapproval

On June 30, 2021, the President signed into law a joint resolution of Congress, S.J. Res. 14, adopted under the CRA, disapproving the 2020 Policy Rule. By the terms of the CRA, the signing into law of the CRA joint resolution of disapproval means that the 2020 Policy Rule is “treated as though [it] had never taken effect.” 5 U.S.C. 801(f). As a result, the VOC and methane standards for the transmission and storage segment, as well as the methane standards for the production and processing segments—all of which had been rescinded in the 2020 Policy Rule—remain in effect. In addition, the EPA's authority and obligation to require the states to regulate existing sources of methane in the Crude Oil and Natural Gas source category under section 111(d) of the CAA also remains in effect.

The CRA resolution did not address the 2020 Technical Rule. Therefore, those amendments remain in effect with respect to the VOC standards for the production and processing segments in effect at the time of its enactment. As part of this rulemaking, in section XII of this document the EPA discusses the impact of the CRA resolution and identifies and finalizes appropriate changes to reinstate the regulatory text that had been rescinded by the 2020 Policy Rule and to resolve any discrepancies in the regulatory text between the 2016 NSPS OOOOa Rule and 2020 Technical Rule.

V. Legal Basis for Final Rule Scope

A. Introduction

The EPA finalizes this rulemaking to revise certain NSPS, to promulgate additional NSPS for both methane and VOC emissions from new oil and gas sources in the production, processing, and transmission and storage segments of the industry; and to promulgate EG to require states to regulate methane emissions from existing sources in those segments. The large amount of methane emissions from the oil and natural gas industry—by far, the largest methane-emitting industry in the nation—coupled with the adverse effects of methane on the global climate compel expeditious regulatory action to mitigate those emissions. This section explains the EPA's legal authority for proceeding with this final action, including regulating methane and VOCs from sources in all segments of the source category, and in so doing, responds to the principal comments received.

In the November 2021 Proposal and the December 2022 Supplemental Proposal, the EPA discussed the history of our regulatory actions for oil and gas sources in the 2016 NSPS OOOOa and the 2020 Policy Rule. See85 FR 63147–53, 86 FR74719–20. These discussions explained the key statutory interpretations and determinations, which we sometimes refer to as the key positions, taken in the 2016 rule that serve as the basis for this action, as well as Congress's endorsement of those positions in adopting the 2021 CRA joint resolution to disapprove the 2020 rule and thereby reinstate the 2016 rule. These discussions further explained that the EPA was not reopening those positions in this rulemaking, but added, for the purpose of informing the public, that the EPA would continue to take the same positions even if Congress had not adopted the joint resolution. The EPA includes those discussions by reference here, and the rest of this section assumes familiarity with them. For convenience, the EPA summarizes them immediately below. The EPA then summarizes the principal comments received and responds to the most significant adverse comments. For the purpose of providing more information to the public, and without reopening the positions in the 2016 rule, the EPA explains why we would take the same positions as in the 2016 rule even if Congress had not adopted the joint resolution as well as the implications of the joint resolution and its legislative history in foreclosing commenters' objections.

B. Overview

This section summarizes why the statutory interpretations the EPA took in the 2016 Rule were correct and why the contrary interpretations taken in the congressionally-voided 2020 Policy Rule were incorrect. These views are confirmed by Congress's reasoning in the legislative history of the CRA resolution and so, for convenience, this section refers to that legislative history as well.

The 2016 NSPS OOOOa established the EPA's authority to regulate GHG emissions from the Crude Oil and Natural Gas source category, in the form of limits on methane emissions. In that rule, the EPA explained that the source category, as the EPA listed it in 1979 for regulation under CAA section 111(b)(1)(A), included the production and processing as well as transmission and storage segments. The EPA also explained that it was justified in promulgating standards of performance for GHG emissions from new sources in the source category because it had a rational basis for doing so. In response to comments, the EPA further explained that once it had listed a source category, it was not required to make, as a predicate to regulating GHG emissions from the source category, an additional pollutant-specific finding that those GHG emissions contribute significantly to dangerous air pollution (termed, a pollutant-specific significant contribution finding).

In addition to providing those explanations, the EPA made two determinations in the 2016 NSPS OOOOa that established alternative legal bases for the GHG NSPS. The first was that the EPA re-listed the source category under CAA section 111(b)(1)(A). To do so, the EPA determined the following: (i) In case the source category did not already include the transmission and storage segment, the EPA revised the source category to include that segment, along with the production and processing segments. The EPA explained that all the segments are interrelated because they comprise parts of a single process of extracting natural gas and preparing it for commercial sale, and that many of the same types of equipment are used in the various segments. (ii) By dint of its emissions of VOC, SO₂, and GHG, the source category thus defined “causes or contributes significantly to air pollution which may reasonably be anticipated to endanger public health or welfare,” under CAA section 111(b)(1)(A). 81 FR 25833–40. For convenience, we refer to this as the endangerment finding, and treat it as having two components: the significant contribution finding and the finding of dangerous air pollution. The second determination was that, in the alternative, if it were necessary to make a pollutant-specific significant contribution finding for GHG emissions as a predicate to promulgating NSPS for GHG from the source category, then the 2016 rule made such a finding. To do so, the rule relied on information concerning the large amounts of methane emissions from the source category. 81 FR 35843.

The 2020 Policy Rule rescinded the above statutory interpretations and determinations. 85 FR 57018. The rule asserted that the transmission and storage segment was not properly included as part of the same source category as the production and processing segments, and was therefore not subject to regulation under CAA section 111. The rule took the position that the transmission and storage segment had not been included in the source category when it was originally listed in 1979, and the 2016 rule's alternative determination to revise the source category was flawed because that segment was not interrelated with the production and processing segments. The rule further asserted that the EPA did not have authority to promulgate NSPS for methane emissions from sources in the production and processing segments because those NSPS were redundant to NSPS for VOC emissions from those sources. The rule further asserted, in the alternative, that the EPA did not have such authority because it was required to make, or was at least authorized to require, a pollutant-specific significant contribution finding for GHG emissions from production and processing sources as a predicate for promulgating NSPS for methane emissions. The rule explained that such a finding was necessary because the EPA had not considered GHG emissions when it listed the source category in 1979. The rule further asserted that the pollutant-specific significant contribution finding in the 2016 NSPS OOOOa was flawed because it had been based in part on emissions from the transmission and storage segment, which, in the rule's view, were not part of the oil and gas source category, and because the EPA had not first established a standard or criteria for determining when emissions contribute significantly, as opposed to simply contribute, to dangerous air pollution. 85 FR 57024–40.

The CRA joint resolution, signed into law by President Biden on June 30, 2021, disapproved the 2020 Policy Rule, and thereby reinstated the 2016 NSPS OOOOa regulation of sources in the transmission and storage segment and regulation of methane emissions from the entire oil and gas source category. 86 FR 63135–36. The legislative history of the CRA resolution—the House Report and a floor statement from Senate sponsors, 167 Cong. Rec. S2282–83 (April 28, 2021) (statement by Sen. Heinrich) (Senate Statement)—made clear Congress's intent that the EPA must regulate methane from the source category under CAA section 111, due to the large amount and impact of those emissions. The legislative history went on to make clear that Congress's basis for disapproving the 2020 rule was that Congress rejected each of the legal interpretations, described above, that underlay the rule. Specifically, the legislative history stated that: the rule was incorrect in removing the transmission and storage segment from the source category; promulgation of NSPS for methane was not redundant with promulgation of NSPS for VOCs, in light of the fact that the former, but not the latter, triggers the requirement to promulgate emission guidelines for existing sources under CAA section 111(d); the EPA is required to promulgate NSPS for a pollutant from a source category when the EPA has a rational basis for doing so, and the EPA cannot decline to promulgate a NSPS on grounds that it is required, or authorized to require, a pollutant-specific significant contribution finding; and the EPA's past approach of relying on a facts-and-circumstances approach to determine significance is acceptable, and an established standard or criteria are not necessary.

In the November 2021 Proposal, the EPA confirmed that it agreed with those interpretations. 86 FR 63151. In the December 2022 Supplemental Proposal, the EPA added that if it were required to make a pollutant-specific significant contribution finding, it would not be required to specify a standard or criterion for determining significance, and that if it were so required, methane emissions from the source category are so large that they would be significant under any reasonable standard or criterion. 87 FR 74719–20 (explaining that the “massive quantities of methane emissions” from the source category, combined with the “potency of methane” are significant in light of, among other things, the fact that the oil and gas sector accounts for 28 percent of U.S. methane emissions or more than the total national emissions of over 160 countries).

C. Comments

Some stakeholders commented adversely. They assert that the November 2021 Proposal and the December 2022 Supplemental Proposal contain what they see as the same flaws as the 2016 NSPS OOOOa. One of these flaws, these commenters assert, is that the EPA is precluded from promulgating requirements for sources in the transmission and storage segment without first listing that segment as a separate source category and making an endangerment finding for GHG emissions from it. According to this view, the source category as listed in 1979 did not include that segment, and that segment must be treated as a separate source category because otherwise, the agency could expand a preexisting source category incrementally, and thereby avoid the CAA section 111 requirements to undertake an endangerment finding before promulgating regulation. A second flaw, according to these commenters, is that regulation of methane is redundant to regulation of VOC. In addition, the commenters assert that CAA section 111 precludes the EPA from promulgating requirements for GHG emissions from the source category without first making a pollutant-specific endangerment finding, including a pollutant-specific significant contribution finding. Moreover, according to the commenters, such a finding must be for methane. In addition, it must be based on an established standard or criteria for determining significance; otherwise, such a finding would be arbitrary and capricious. According to these commenters, CAA section 111 does not authorize the EPA to regulate air pollutants from a listed source category on the grounds that it has a rational basis for such regulation. These commenters further assert that although the CRA resolution disapproved the 2020 Policy Rule, it did not change the underlying requirements of CAA section 111, so that these flaws in the EPA's regulatory approach remained. They argue that only the legislative language of the joint resolution, and not the accompanying legislative history, is relevant.

Other commenters supported the November 2021 Proposal and December 2022 Supplemental Proposal. They state that the 2016 NSPS OOOOa established an appropriate basis for promulgating regulations to control methane emissions from the oil and gas industry. They state that the 1979 source category listing included the transmission and storage segment, and that in any event, the 2016 rule correctly determined that the transmission and storage segment was interrelated with the other segments and thus merited inclusion in the revised source category. They also state that regulation of methane from this source category is not redundant to regulation of VOCs. They add that because the EPA previously determined that the oil and gas source category causes or contributes significantly to dangerous air pollution, the EPA is authorized to promulgate a NSPS for methane because it is rational to do so in light of the large amount of methane emissions from the source category. For this reason, commenters assert, it would be arbitrary and capricious for the EPA to decline to regulate methane emissions from the source category. Commenters add that a pollutant-specific significant contribution or endangerment finding for methane is neither necessary nor authorized by CAA section 111; that any such findings under CAA section 111 should be made on the basis of the facts and circumstances, and not a predetermined standard or threshold; and that in any event, the large amounts of methane emissions from the source category must be considered to be significant under any reasonable definition. Commenters also note that the 2016 rule made an appropriate significant finding contribution for GHG from the source category in the alternative. Commenters also assert that Congress's disapproval of the 2020 Policy Rule through the CRA joint resolution reaffirmed the 2016 rule's positions.

D. Response to Comments and Discussion

The adverse arguments by commenters described above concern the positions in the 2016 NSPS OOOOa, which also provide the basis for this rulemaking, and the significance of the CRA joint resolution and its legislative history. The commenters' arguments concerning the positions in the 2016 rule were rejected in the 2016 rule itself, adopted in the 2020 Policy Rule, and then rejected in the legislative history of the joint resolution. The EPA stated in the November 2021 Proposal and December 2022 Supplemental Proposal that it was not reopening these positions, and we maintain that decision here. However, again, solely for the purpose of informing the public, we provide responses to the commenters' arguments immediately below and in the response to comment document. Our decision not to reopen the positions in the 2016 rule does not apply to issues concerning the joint resolution, which post-dated the 2016 rule. Accordingly, the EPA responds in more detail further below to the commenters' arguments concerning the joint resolution.

1. Commenters' Arguments Concerning the Key Positions in the 2016 NSPS OOOOa

Stakeholders submitted adverse comments on key positions, including statutory interpretations and determinations, that the EPA made in the 2016 NSPS OOOOa and that serve as the foundation for the present action. These adverse comments generally mirrored those made in the course of the 2016 NSPS OOOOa rulemaking and the rationale for the 2020 Policy Rule, and did not raise significant new points not addressed in the 2016 NSPS OOOOa or the November 2021 Proposal and December 2022 Supplemental Proposal. The EPA continues to disagree with those comments.

a. Scope of the Oil and Gas Source Category as Listed in 1979

i. Scope of the Source Category as Listed in 1979

The 2016 NSPS OOOOa stated that the Crude Oil and Natural Gas Production source category, as the EPA listed it for regulation under CAA section 111(b)(1)(A) in 1979, included the transmission and storage segment, along with the other two major segments of the industry, the production and processing segments. Based on this understanding, the EPA continued to promulgate NSPS for sources in that segment, after it had begun to do so in the 2012 NSPS OOOO. Adverse commenters on the November 2021 Proposal took the contrary view, reiterating adverse comments on the 2016 rule. However, the 2016 rule was correct—the EPA's 1979 listing of the source category should be considered to have included the transmission and storage segment.

The commenters' argument stems from the fact that the 1979 listing, 44 FR 49222 (Aug. 21, 1979) (1979 Listing Rule), identified the source category as “Crude Oil and Natural Gas Production,” and did not specifically identify the transmission and storage segment as part of the source category. See44 FR 49222 (citing Priorities for New Source Performance Standards Under the Clean Air Act Amendments of 1977, EPA–450/3–78–019 (April 1978) (“1978 Priority List”)). This argument fails to recognize the comprehensive approach that the EPA undertook in the 1979 Listing Rule, which strongly indicates that the oil and gas source category included the transmission and storage segment. In the 1979 Listing Rule, the EPA determined that numerous source categories met the CAA section 111(b)(1)(B) requirements to be listed for regulation. The EPA based that determination on a study it had undertaken in 1978, the 1978 Priorities List, that comprehensively identified all source categories in the United States—203 in number—and indicated which ones should and should not be listed. That study identified the oil and gas source category as the “Crude Oil and Natural Gas Production Plants,” a name that referenced only the production segment of the oil and gas industry. However, the study, and the 1979 Listing Rule, which identified the source category as “Crude Oil and Natural Gas Production,” clearly intended the source category to be broader than just that segment, consistent with the fact that the 1978 Priorities List was designed to be comprehensive. This is evident because in 1985, the EPA promulgated the first set of NSPS for the source category, which concerned sources in the processing segment, not the production segment. 50 FR 26122 (June 24, 1985) (VOC emissions from equipment leaks), 50 FR 40158 (Oct. 1, 1985) (SO₂ emissions). It is evident that the source category, as listed in 1979, also included the third major segment of the industry, the transmission and storage segment. Otherwise, the 1978 Priorities List, which was designed to be comprehensive, would have completely overlooked this major segment, which is not plausible.

ii. Alternative Determination in 2016 NSPS OOOOa To Include Transmission and Storage Segment in Source Category

In addition, in the 2016 NSPS OOOOa, in the alternative, and on the assumption that the source category as listed in 1979 did not include the transmission and storage segment, the EPA revised the source category to include that segment, and relisted that source category—which it termed the Crude Oil and Natural Gas source category—under CAA section 111(b)(1)(A). 81 FR 35832–40. This alternative determination further addresses commenters' objections.

The EPA has broad discretion in determining the scope of the source category, which is reviewable under the arbitrary and capricious standard of CAA section 307(d)(9). In the 2016 NSPS OOOOa, the EPA determined that the transmission and storage segment was “interrelated” with the production and processing segments and therefore should be included in the same source category, the EPA provided sound reasons for doing so. 81 FR 35832. This reasoning is consistent with the ordinary understanding of the term, “category.” Merriam-Webster defines “category” as “any of several fundamental and distinct classes to which entities or concepts belong,” and it defines a “class [ ]” as “a group, set, or kind sharing common attributes.” Treating all those segments as part of the source category meets this definition because, as the EPA explained in the 2016 NSPS OOOOa, the segments all included operations that were a sequence of functions in a multi-step process that is necessary to achieve the common goal of preparing recovered gas for distribution. Moreover, the segments had common equipment and control technology. 81 FR 35832. In the 2016 rule, the EPA went on to assess the air pollutants emitted from the source category, including VOC, SO₂, and GHG; as well as the associated air pollution, including hazardous air pollution, tropospheric ozone, SO₂, and atmospheric GHG; and determined that the source category causes or contributes significantly to air pollution which may reasonably be anticipated to endanger public health or welfare. Id. 35840. The EPA has not reopened that endangerment finding.

This re-listing addresses the commenters' objections concerning the regulation of sources in the transmission and storage segment. By properly including the segment in a source category and listing that source category under CAA section 111(b)(1)(A), the EPA established the predicate for such regulation.

b. Reliance on Rational Basis Test, and Rejection of Pollutant-Specific Significant Contribution Finding, for Regulating GHG From the Source Category

In the 2016 NSPS OOOOa, the EPA interpreted CAA section 111 to authorize regulation of methane emissions from the oil and gas source category because the large amount of those emissions provided a rational basis for such regulation. 81 FR 35842. The EPA went on to determine that it had a rational basis to regulate methane emissions from the source category on grounds that, among other things, the oil and gas industry is the largest industrial emitter of methane in the U.S. Id. 35842–43. As stated in section III, human emissions of methane, a potent GHG, are responsible for about one third of the warming due to well-mixed GHGs, which makes methane the second most important human warming agent after carbon dioxide. The EPA has not reopened that determination in the present rulemaking.

However, commenters asserted that under CAA section 111, a rational basis determination is insufficient as a predicate for regulation, and, instead, the EPA was required to determine that methane emissions from the oil and gas source category cause or contribute significantly to air pollution that is reasonably anticipated to endanger public health or welfare. Commenters took this same position in the 2016 NSPS OOOOa. For the reasons discussed immediately below, we disagree with commenters and we confirm the position in the 2016 rule. As we discuss further below, the 2016 rule also addressed commenters' objections by making a finding that the GHG emissions from the oil and gas source category contribute significantly to dangerous air pollution.

CAA section 111 is clear in authorizing the EPA to regulate air pollutants from a listed source category if it has a rational basis for doing so, and does not require, or authorize the EPA to require, a pollutant-specific significant contribution finding or endangerment finding as a predicate for such regulation. CAA section 111(b)(1)(A) requires the EPA to “publish . . . a list of categories of stationary sources” for regulation, and to “include a source category in such list if . . . it causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare.” CAA section 111(b)(1)(B) provides that within a specified time after listing the source category, the EPA shall promulgate “standards of performance for new sources within such category.” CAA section 111(a)(1) defines “standard of performance” (in the singular) as “a standard for emissions of air pollutants” that is determined in a particular manner. CAA section 307(d)(1)(C) provides that the EPA's promulgation of standards of performance under CAA section 111 are subject to the requirements of CAA section 307(d). Those requirements include the judicial review provisions of CAA section 307(d)(9)(A), which provide that a court may reverse standards of performance “found to be arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with law.”

By their terms, these provisions require the EPA to make an endangerment finding, including a significant contribution finding, for a source category as a predicate to promulgating standards of performance, and they establish detailed requirements that standards of performance must meet. However, by their terms, they do not require, or authorize the EPA to require, any significant contribution or endangerment findings for particular air pollutants as a predicate to promulgating such standards. Instead, the EPA's promulgation of such standards is subject to the CAA section 307(d)(9)(A) arbitrary and capricious standard for judicial review. See American Electric Power Co. v. Connecticut, 564 U.S. 410, 424, 427 (2011). In contrast, numerous other provisions explicitly require a pollutant-specific contribution or endangerment finding. See, e.g., CAA section 183(f)(1)(A), 202(a)(1), 211(c)(1)(A), 213(a)(1)–(3), 231(a)(2). The inclusion of clear requirements for pollutant-specific findings in other CAA provisions confirms that the absence of such a requirement in CAA section 111 indicates Congress' intention not to include such a requirement there. See United States v. Gonzales, 520 U.S. 1, 5 (1997) (“Where Congress includes particular language in one section of a statute but omits it in another section of the same Act, it is generally presumed that Congress acts intentionally and purposely in the disparate inclusion or exclusion.”) (internal quotations omitted).

Importantly, the arbitrary and capricious standard is tantamount to a standard of reasonableness or rationality. See Motor Vehicle Mfrs. Ass'n of U.S., Inc. v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 42–43 (1983) ( Motor Vehicle Mfrs. Ass'n) (“[t]he scope of review under the `arbitrary and capricious' standard” means that a court “may not set aside an agency rule that is [, among other things,] rational”). In the 2016 NSPS OOOOa, the EPA termed this standard the rational basis test, and applied it to the promulgation of GHG standards of performance for the oil and gas source category. This standard of review is well established, and courts routinely review rules under it, as noted in the House Report at 11.

On the other hand, requiring a pollutant-specific significant contribution finding as a predicate for promulgating NSPS would disrupt the scheme Congress set out because it would render the significant contribution and endangerment findings for the source category superfluous. This is because a finding that any particular air pollutant emitted from a source category contributes significantly to dangerous air pollution necessarily means that the source category itself contributes significantly to dangerous air pollution. See TRW Inc. v. Andrews, 534 U.S. 19, 31 (2001) (“It is a cardinal principle of statutory construction that a statute ought, upon the whole, to be so construed that, if it can be prevented, no clause, sentence, or word shall be superfluous. . . .”).

The EPA's more than half-century long regulatory history of CAA section 111 is consistent with the rational basis test and provides no precedent for requiring or authorizing the EPA to require a pollutant-specific significant contribution finding. The EPA first listed source categories and promulgated standards of performance for them in 1971, 36 FR 5931 (Mar. 31, 1971) (listing initial source categories); 36 FR 24876 (Dec. 23, 1971) (promulgating initial standards of performance), and since then, has listed dozens more source categories and promulgated hundreds of standards. 40 CFR part 60. The EPA has always listed source categories by determining that they contribute significantly to dangerous air pollution, and then has proceeded to promulgate NSPS for particular air pollutants from the source categories, without making comparable significant contribution or endangerment findings for those air pollutants. The EPA has followed this approach when it has promulgated standards of performance for particular air pollutants at approximately the same time that it listed the source category, see, e.g.,36 FR 5931 (Mar. 31, 1971) (listing five source categories); 36 FR 24876 (Dec. 23, 1971) (promulgating standards of performance for same five source categories), and when it has promulgated standards of performance for particular air pollutants for the first time many years after it listed the source category, and which it did not address when it listed the source category. See38 FR 15380 (June 11, 1973) (listing the petroleum refineries source category), 39 FR 9310 (Mar. 8, 1974) (promulgating standards of performance for PM, CO, SO₂, and opacity from the source category), 73 FR 35838 (June 24, 2008) (promulgating standards of performance for NO_X and VOC from the source category).

In other rulemakings, the EPA declined to promulgate NSPS for certain air pollutants, on the basis of what amounted to a rational basis test, although the EPA did not use that specific terminology. See42 FR 22056, 22507 (May 3, 1977) (declining to promulgate NSPS for NO_X, CO, and SO₂ from lime manufacturing plants due to limited amounts of emissions of pollutants or limited reductions that controls would achieve); National Lime Assoc. v. EPA, 627 F.2d 416, 426 & n.27 (D.C. Cir. 1980). On the other hand, in rulemakings since 2009, the EPA has rejected comments that it was required to make a pollutant-specific significant contribution finding. See74 FR 51950, 51957 (Oct. 8, 2009) (NSPS for coal preparation and processing plant source category); 80 FR 64510, 64530 (Oct. 23, 2015) (NSPS for GHG from electric utility generation source category); 2016 NSPS OOOOa, 81 FR 35843.

It is clear that interpreting CAA section 111 to require, or authorize the EPA to require, a pollutant-specific significant contribution finding as a predicate for regulation is novel and departs from the EPA's lengthy history of promulgating standards of performance. This “consistent and longstanding interpretation of the agency charged with administering the statute” further supports interpreting CAA section 111 to base the promulgation of standards of performance on a rational basis standard, consistent with CAA section 307(d)(9)(A), and not to require a pollutant-specific significant contribution finding. See Entergy Corp. v. Riverkeeper, Inc., 556 U.S. 208, 235 (2009). Indeed, interpreting CAA section 111 to require, or authorize the EPA to require, a pollutant-specific significant contribution finding as a predicate for regulation would undermine the EPA's implementation of CAA section 111 to date, including, in particular, virtually all of the standards of performance the EPA has promulgated to date.

In addition, even if commenters are correct that CAA section 111 requires a pollutant-specific finding, that finding should be simply a contribution, not a significant contribution. A contribution finding would be consistent with Congress's approach in other CAA provisions. See, e.g., CAA section 183(f)(1)(A), 202(a)(1), 211(c)(1), 231(a)(2). A significant contribution finding is illogical because it would render the source category significant contribution finding under CAA section 111(b)(1)(A) superfluous, as noted above. By analogy, CAA section 213(a)(4) explicitly requires the EPA make two findings, but differentiates them: (1) emissions from new nonroad engines or vehicles contribute significantly to an air pollution problem, and (2) emissions from classes or categories of new nonroad engines or vehicles cause or contribute to the air pollution problem. Accordingly, if CAA section 111 were interpreted to require, or at least authorize, the EPA to require a pollutant-specific finding as a predicate for regulation, that finding should be that the source category's emissions of the pollutant cause or contribute to dangerous air pollution.

c. Lack of Redundancy of Regulation of Methane

Commenters also argued that the GHG NSPS in the oil and gas source category are redundant to the VOC NSPS. Adverse commenters had made this objection during the 2016 NSPS OOOOa. We rejected it there and reject it here as well.

In the 2016 rule, the EPA structured the requirements of the VOC and GHG NSPS to mirror each other, and it is that structure that forms the basis for commenters' argument that the GHG NSPS should be considered to be redundant. Because the EPA had listed the oil and gas source category for regulation, it was required to promulgate NSPS for GHG emissions under CAA section 111(b)(1)(B) (as long as doing so was rational), and that requirement is not eliminated by the fact that the GHG NSPS could be structured to mirror the VOC NSPS. Moreover, the fact that the 2016 rule structured the requirements as it did does not mean they are redundant, only that the EPA sought to allow sources to comply with them as efficiently as possible. Had the EPA not been careful to structure the two sets of NSPS to mirror each other, no argument would have arisen that the GHG NSPS were redundant, but that would have been an inefficient regulatory scheme.

Most importantly, the GHG NSPS are not redundant because only they, and not the VOC NSPS, trigger the requirement that existing sources are subject to GHG emission guidelines under CAA section 111(d). The large contribution of methane emissions from the source category to dangerous air pollution driving the grave and growing threat of climate change means that, in the agency's judgment, it would be arbitrary and capricious under CAA section 307(d)(9)(A)—as well as highly irresponsible—for the EPA to decline to promulgate NSPS for methane emissions from the source category. See American Electric Power, 564 U.S. at 426–27.

d. Alternative Determination in the 2016 NSPS OOOOa for a Pollutant-Specific Endangerment Finding

The 2016 NSPS OOOOa re-listing of the source category, described above, included another alternative determination that provided an additional basis for the regulation of GHG emissions, which was that the EPA explicitly determined that GHG emissions from the Crude Oil and Natural Gas source category cause or contribute significantly to dangerous air pollution. 81 FR 35833–40. This determination—which, to be clear, the EPA is not required to do, but nevertheless did so in the alternative—further addressed commenters' objections that the EPA was required to make such a pollutant-specific determination as a predicate for regulating methane emissions. The EPA has not reopened this determination.

As noted above, this type of determination entails two findings, a significant contribution finding and a finding of dangerous air pollution. In this case, those findings were for GHG emissions. We refer to the former as the pollutant-specific significant contribution finding. In the 2016 rule, the EPA based the pollutant-specific significant contribution finding on the same facts concerning the large amount of methane emissions from the oil and gas source category that it relied on in making the rational basis determination, as noted above. Id. 35842–43. It made the finding of dangerous air pollution based on the endangerment finding for GHG that the EPA made under CAA section 202(a) in 2009 (the 2009 Endangerment Finding) and the 2010 denial of petitions to reconsider, updated with more recent information. See Coalition for Responsible Regulation v. EPA, 684 F.3d 102, 117–123 (D.C. Cir. 2012) (upholding the 2009 Endangerment Finding and 2010 denial of petitions to reconsider, and noting, among other things, the “substantial . . . body of scientific evidence marshaled by EPA in support”).

This pollutant-specific determination for GHG from the oil and gas source category addresses the commenters' arguments that the EPA cannot regulate GHG from the source category without making such a finding. See American Lung Ass'n v. EPA, 985 F.3d 914, 974–77 (D.C. Cir. 2021) ( American Lung Ass'n) (the pollutant-specific significant-contribution finding that the EPA made in the alternative for GHG emissions from electric power plants provided a sufficient basis for regulation and addressed petitioners' arguments that the NSPS for GHG emissions from those sources was invalid due to lack of such a finding), rev'd in part sub nom West Virginia v. EPA, 142 S.Ct. 2587 (2022) ( West Virginia ).

Commenters also argued that an endangerment finding specifically for methane emissions—that is, a determination that methane emissions from the oil and gas source category cause or contribute significantly to atmospheric levels of methane, and that those levels may reasonably be anticipated to endanger public health or welfare—is necessary as a predicate for regulation of methane emissions from the source category. The EPA responded to the same comment in the 2016 NSPS OOOOa. 81 FR 35841–42, 35877. The EPA is not reopening this issue, but for the purpose of providing information to the public, will explain why, assuming that a pollutant-specific determination is necessary as a predicate for CAA section 111 regulation, it is appropriate for the EPA to make the significant contribution finding on the basis of GHG emissions and for the EPA to rely on the finding of dangerous air pollution that it made for GHG, and it is not necessary for the EPA to make comparable determinations for methane emissions.

The EPA's approach in the 2016 NSPS OOOOa to make the findings for GHG is fully consistent with other rulemakings in which this issue arose. The first was the 2009 Endangerment Finding. 74 FR 66496. CAA section 202(a)(1) requires the EPA to establish “standards applicable to the emission of any air pollutant from any class or classes of new motor vehicles or new motor vehicle engines” that “in his judgment cause, or contribute to, air pollution which may reasonably be anticipated to endanger public health or welfare.” The EPA explained that this provision sets forth a two-part test for regulatory action: first, whether the relevant air pollution may reasonably be anticipated to endanger public health or welfare, and second, whether emissions of any air pollutant from the class or classes of the sources in question (there, new motor vehicles) cause or contribute to this air pollution. 74 FR 66505, 66516, 66536. The EPA explained that “the air pollution can be thought of as the total, cumulative stock in the atmosphere, while the air pollutant can be thought of as the flow that changes the size of the total stock.” 74 FR 66536 (emphasis omitted). The EPA went on to explain that the “air pollution” that it was determining endangered public health and welfare is the elevated atmospheric concentrations of “the combined mix of six key directly-emitted, long-lived and well-mixed greenhouse gases”—carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluorides. Id. 66516–23. The EPA supported this conclusion by explaining, among other things, that these six gases have the common attributes regarding their climate effects. Id. 66517. For the same reasons, in the 2009 Endangerment Finding, the EPA also defined the air pollutant as GHG—a single air pollutant made up of the same six gases in an aggregate group for purposes of determining whether the air pollutant causes or contributes to the endangering air pollution. Id. 66537. The EPA explained that “they are all greenhouse gases that are directly emitted . . .; they are sufficiently long-lived in the atmosphere such that, once emitted, concentrations of each gas become well mixed throughout the entire global atmosphere; and they exert a climate warming effect by trapping outgoing, infrared heat that would otherwise escape to space. Moreover, the radiative forcing effect of these six greenhouse gases is well understood.” Id. The EPA further explained that this definition of the GHG air pollutant was reasonable, even if emissions from the source category did not include all six gases. Id. In fact, in the 2009 Endangerment Finding, the EPA noted that the emissions from the relevant class or classes of new motor vehicles or new motor vehicle engines included only four of the gases. Id. 66538, 66541. As noted in section III.A.1 above, the oil and gas source category emits methane and CO_2, although the limits established in this action focus on regulating GHG through requirements that are expressed in the form of limits on methane, as a constituent of the GHG air pollutant.

In subsequent actions that entailed or referenced GHG endangerment findings, the EPA has taken the same position that the air pollution consists of the elevated atmospheric concentrations of these six greenhouse gases and the air pollutant consists of the mix of the same six gases. 81 FR 54422 (2016 GHG endangerment and cause or contribute finding for certain aircraft under CAA section 231(a)(2)(A)). The EPA took this same position in the 2016 NSPS OOOOa, as mentioned at the beginning of this section. 81 FR 35833, 35877. For the same reasons that the EPA has consistently articulated in the 2009 Endangerment Finding and afterwards, it is appropriate to base that determination on the contribution of GHG emitted from the source category to atmospheric GHG levels. This is because, as noted above, the 2016 rule identifies the air pollutant as GHG, even though it expresses the requirements in the form of limits on methane. 40 CFR 60.5360a. Any significant contribution finding must address the pollutant being regulated, in this case, GHG. In addition, for the finding of dangerous air pollution, the air pollution of concern is the elevated concentration of the six well-mixed greenhouse gases, and not only concentrations of methane.

e. Standards or Criteria for Determining Significance

Commenters argued that when the EPA makes a significant contribution determination for the pollutant and the source category as a predicate for regulation, the EPA must first establish a standard or criteria for when a contribution is significant. They stated that such a standard or criteria is necessary to allow the EPA to distinguish between a contribution and a significant contribution, and that without it, the significant contribution finding is arbitrary. The EPA disagrees with this comment. Rather, it is fully appropriate for the EPA to exercise its discretion to employ a facts-and-circumstances approach, particularly in light of the wide range of source categories and the air pollutants they emit that the EPA must regulate under CAA section 111.

With respect to the significant contribution finding for a source category, CAA section 111(b)(1)(A) by its terms does not require that such a finding be based on established criteria or a standard or threshold. In fact, during the 50 years that it has listed dozens of source categories, the EPA has never identified a standard or criteria for determining significance, and instead, has always relied on the particular facts and circumstances. This approach is appropriate because Congress intended that CAA section 111 apply to a wide range of source categories and pollutants, from wood heaters to emergency backup engines to petroleum refineries. In that context, it is reasonable to interpret CAA section 111 to allow the EPA the discretion to determine how best to assess significant contribution and endangerment based on the individual circumstances of each pollutant and each source category. For example, among the six well-mixed gases that comprise GHG, CO₂ is emitted in the greatest quantities while methane emissions have a greater impact than CO₂ emissions on a per-ton basis. In addition, source categories that emit the same air pollutant may differ from each other in several ways that may be relevant for purposes of a significance finding, including whether new sources are expected to be constructed.

With respect to any significant contribution finding for an air pollutant—and as noted above, CAA section 111 does not require one as a predicate for regulation—established criteria or standards are also not required. The D.C. Circuit adopted this position in American Lung Ass'n, 985 F.3d at 976–77, when it upheld the EPA's pollutant-specific significant-contribution finding for GHG emissions from electric power plants even though the EPA did not “articulate a specific threshold measurement for significance.” The court relied on the same reasoning that it used when, in upholding the 2009 Endangerment Finding, it rejected an argument that the EPA must establish criteria in order to determine that an air pollutant endangers public health and welfare. Coal. for Responsible Regulation, Inc. v. EPA, 684 F.3d 102 (D.C. Cir. 2012). The court stated that “EPA need not establish a minimum threshold of risk or harm before determining whether an air pollutant endangers” because “the inquiry necessarily entails a case-by-case, sliding-scale approach.” Id. at 122–23. Although there, the court was discussing whether an air pollutant endangers public health or welfare, the court later, in American Lung Ass'n, made clear that the same principle applies to whether an air pollutant contributes significantly to dangerous air pollution. On this point, as well, the EPA is in full agreement with the statements in the House Report stating that the EPA is not required to base a significance finding on an established standard or criteria. House Report at 9–10.

Commenters who interpret CAA section 111 to require a pollutant-specific significant contribution finding rely on the requirement in CAA section 111(b)(1)(A) for a source-category significant endangerment finding. By that logic, the facts-and-circumstances method by which the EPA has always determined the source category significant-contribution finding should also apply to any pollutant-specific significant contribution finding. See Alaska Dep't of Envtl. Conservation, 540 U.S. 461, 487 (2004) (explaining, in a case under the CAA, “[w]e normally accord particular deference to an agency interpretation of longstanding duration” (internal quotation marks omitted) (citing Barnhart v. Walton, 535 U.S. 212, 220 (2002)). In fact, in each of the first two rules in which the EPA made a pollutant-specific significant contribution finding as an alternative basis for regulating GHG from the relevant source category, the EPA relied on a facts-and-circumstances test for determining significance. 80 FR 64531 (NSPS for GHG from electric power plants); 2016 NSPS OOOOa, 81 FR 35843. The EPA's long track record for basing CAA section 111 significance findings on an examination of facts and circumstances, and not relying on established criteria or other standards or thresholds, coupled with the importance of allowing the EPA the flexibility to take into account the particular circumstances of the pollutant and the source category, makes clear that a lack of such criteria or standards does not render the significance determinations arbitrary and capricious. The courts have long reviewed agency actions under the arbitrary-and-capricious standard without requiring quantitative or numerical standards. See Motor Vehicle Mfrs. Ass'n, 463 U.S. 42–43 (stating that the court “may not set aside an agency rule that is rational, based on consideration of the relevant factors and within the scope of the authority delegated to the agency by the statute”).

Other CAA provisions require the EPA to make a pollutant-specific determination, and the EPA's actions under these provisions are informative here as well. The EPA has implemented some of these provisions through a facts and circumstances test, see59 FR 31308 (June 17, 1994) (under CAA section 213, in determining whether emissions from nonroad engines and vehicles contribute significantly to dangerous air pollution, the EPA made a qualitative assessment, and rejected assertions by commenters that it was required to determine a specific numerical standard for significance); and has implemented some of these provisions through both a facts and circumstances test and criteria or standards. See84 FR 50268 (Sept. 24, 2019) (proposal for 2020 Policy Rule; discusses EPA action under CAA section 189(e), which requires the EPA to regulate sources of precursors to PM₁₀ except where EPA determines such sources do not contribute significantly to PM₁₀ levels that exceed the NAAQS; EPA has determined significance through a combination of a facts-and-circumstances test and criteria); compare id. at 50267–68 (discussing EPA's implementation of CAA section 110(a)(2)(D)(i), the Good Neighbor Provision, which requires states to prohibit emissions “in amounts which will contribute significantly to nonattainment” of the NAAQS in any other state; in rules concerning ozone and PM_2.5, the EPA has identified a numerical criterion for determining significant contribution) with84 FR 54498, 54499 (October 10, 2019) (in rules under the Good Neighbor Provision concerning the SO₂ NAAQS, EPA has applied a weight of evidence (that is, evaluating all available facts and circumstances) test for determining whether there is significant contribution). The fact that the EPA has sometimes relied on a facts-and-circumstances test for determining significance in these CAA provisions supports its view that such a test is reasonable under CAA section 111.

If the EPA were required to develop a standard or criteria to determine significance, any reasonable standard or criteria would necessarily focus on the amount of emissions from the source category and the harmfulness of the pollutant emitted. In the case of the oil and gas source category, the “massive quantities of methane emissions” contributed by the sector to the levels of well-mixed GHG in the atmosphere, as described in the November 2021 Proposal, 86 FR 63148, coupled with the potency of methane (with a global warming potential (GWP) of almost 30 or more than 80, depending on the time period of the impacts, id. 63130), demonstrate that the source category's GHG emissions would be significant under any reasonable criteria-based approach. See86 FR 63131.

In particular, the fact that the oil and gas source category has the largest amount of methane emissions in the United States, in the context of a problem such as climate change that is caused by the collective contribution of many different sources, confirms that those emissions would meet any reasonable standard or criteria for significance. See American Lung Ass'n, 985 F.3d at 977 (“The global nature of the air pollution problem means that `[a] country or a source may be a large contributor, in comparison to other countries or sources, even though its percentage contribution may appear relatively small' in the context of total emissions worldwide.” (quoting 2009 Endangerment Findings). In fact, as noted above and discussed at further length in the December 2022 Supplemental Proposal, 87 FR 74719–20, the oil and gas source category's position as the largest methane-emitting source category in the U.S. would itself qualify as a criterion that supports treating it as a significant contributor of methane, if such a criterion were necessary.

2. Commenters' Arguments Concerning the CRA Joint Resolution and its Legislative History

Commenters dismiss the significance of the CRA joint resolution that disapproved the 2020 Policy Rule by arguing that although the joint resolution had the effect of reinstating the 2016 NSPS OOOOa, it did not change the underlying requirements of CAA section 111, so that the flaws the commenters perceived in the 2016 rule's positions remained. The commenters further argue that the legislative history of the joint resolution that supported the 2016 rule's positions is irrelevant. We disagree with these commenters. Under the CRA, the enactment of the joint resolution not only disapproved the 2020 Policy Rule and had the effect of reinstating the 2016 rule, it also prohibited the EPA from promulgating another rule that is “substantially the same” as the 2020 Policy Rule. CRA section 801(b)(2). The joint resolution, confirmed by its legislative history, made clear what rules would and would not be prohibited. The commenters' arguments, if accepted, would lead to the adoption of a rule that would be considered substantially the same as the 2020 rule, and for that reason, their arguments must be rejected. In this section, we provide background information concerning the CRA and the role of legislative history, we summarize the discussion in the joint resolution's legislative history, and then we explain why commenters' arguments must be rejected.

a. The CRA Joint Resolution of Disapproval

Congress enacted the CRA in 1996 to facilitate Congressional oversight of agency action by streamlining the process for adopting legislation to disapprove agency rules. The CRA provides the specific wording for a joint resolution of disapproval for an agency action, which is a sentence that states (including the standard prefatory phrase for a joint resolution): “Resolved by the Senate and House of Representatives of the United States of America in Congress assembled, That Congress disapproves the rule submitted by the __ relating to __, and such rule shall have no force or effect.” 5 U.S.C. 802(a). The blank spaces are for the name of the agency and the rule. The CRA further provides that after Congress adopts a joint resolution of disapproval of an agency rule, the agency is precluded from promulgating a new rule that is “substantially the same” as the disapproved rule, absent a new act of Congress authorizing such a rule. CRA section 801(b)(2).

Notwithstanding this constraint, the affected agency may still have the discretion to, and in fact may still be required to, promulgate further rulemaking in accordance with the underlying statute that authorized the disapproved rule. The legislative history of the joint resolution may clarify the parts of the disapproved rule that Congress objected to, and thereby clarify what subsequent rules would or would not be substantially the same as the disapproved rule. The potential importance of legislative history that accompanies a joint resolution and that explains Congress's objections to the rule, is highlighted by the fact that the legislative language of the joint resolution is, by the terms of the CRA, simply a one-sentence disapproval of the agency action, as noted above.

b. CRA Joint Resolution of Disapproval of the 2020 Policy Rule

The joint resolution of disapproval of the 2020 Policy Rule provided, consistent with the form mandated under the CRA, “Resolved by the Senate and House of Representatives of the United States of America in Congress assembled, That Congress disapproves the rule submitted by the Administrator of the Environmental Protection Agency relating to “Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources Review” (85 FR 57018 (September 14, 2020)), and such rule shall have no force or effect.” In adopting it, Congress explained its understanding of CAA section 111 and, based on that, its reasons why the 2020 Policy Rule was inconsistent with CAA section 111 and must be disapproved. Specifically, as discussed in the November 2021 Proposal and summarized above, the Senate floor debate over the joint resolution and the House Report made clear Congress's views concerning the relevant provisions of CAA section 111 and the statutory interpretations contained in the 2016 NSPS OOOOa and the 2020 Policy Rule, and its intention that the EPA take further rulemaking action consistent with those views. Thus, the legislative history made clear that Congress (i) intended the EPA to treat the transmission and storage segment as part of the Crude Oil and Natural Gas Production source category and to promulgate NSPS and emission guidelines for GHG from the source category, (ii) viewed the 2016 rule's statutory interpretations of CAA section 111 to be correct and to serve as the basis for these regulatory actions, and (iii) viewed the contrary statutory interpretations contained in the 2020 rule to be incorrect. The statutory interpretations that Congress viewed to be correct include that the EPA is not authorized to promulgate a pollutant-specific significant contribution finding as a predicate for regulation, and that a facts and circumstances test for determining significant contribution for the source category listing is appropriate.

c. Commenters' Arguments and the EPA's Responses

Commenters assert that while the CRA joint resolution disapproved the 2020 Policy Rule, that action did not extend to the legal rationale and policy positions in the 2020 rule, and did not endorse the legal rationale and policy positions in the 2016 rule. They also assert that only the text of the joint resolution—again, a single sentence, quoted above, stating that Congress disapproves the 2020 rule and it shall have no force or effect—is relevant, and that the legislative history is not relevant. The commenters then assert that the joint resolution did not change the requirements of CAA section 111. From there, they assert that CAA section 111 requires the interpretations and determinations that the 2020 Policy Rule made, including that in order for the EPA to promulgate NSPS for sources in the transmission and storage segment, the EPA must first list that segment as a separate source category, including making significant contribution and endangerment findings for it; and in order for the EPA to promulgate NSPS for GHG emissions from oil and gas sources, the EPA must first make a pollutant-specific significant contribution finding, including specifying a standard or criterion for significance.

The EPA rejects the commenters' arguments. In essence, commenters seek to minimize the importance of the joint resolution in order to argue that the EPA must rescind most of the 2016 NSPS OOOOa on grounds that it is inconsistent with CAA section 111's requirements, as the commenters see them. However, such a rescission rule would be substantially the same as the 2020 Policy Rule, and is therefore precluded by the joint resolution.

The central features of the disapproved 2020 Policy Rule were its position that the transmission and storage segment is separate from the production and processing segments; its position that a GHG-specific significant contribution finding, supported by standards or criteria for determining significance, was a necessary predicate for regulating GHG emissions; and the statutory interpretations that underlay those positions. In addition, the legislative history of the CRA resolution made clear that Congress disapproved the 2020 Policy Rule because it rejected those positions and the underlying legal interpretations. Thus, a rule that adopted the same positions and interpretations as the 2020 Policy Rule would be precluded by the joint resolution as substantially the same as the 2020 Policy Rule.

Looked at another way, the commenters' in essence argue that the EPA should withdraw the November 2021 Proposal and the December 2022 Supplemental Proposal and instead propose and promulgate a rule stating that the EPA is not authorized to further regulate oil and gas sources, including promulgating emission guidelines, unless it lists the transmission and storage segment as a separate source category and makes a pollutant-specific significant contribution finding for GHGs, based on standards or criteria for determining significance. However, such a rule would also be precluded by the joint resolution as substantially the same as the key aspects of the 2020 Policy Rule because it would be based on the same statutory interpretations as that rule. Indeed, it is difficult to see what effect the disapproval would have if not to preclude the EPA from re-instating the positions and underlying legal interpretations included in the 2020 Policy Rule.

These commenters also err in asserting that the legislative history is irrelevant. Agencies and courts regularly look to legislative history to inform their actions and decisions. This makes particular sense in the case of a CRA joint resolution given the very limited language Congress may use in the joint resolution itself. Commenters also argue that the EPA's position that the joint resolution of disapproval applies to the legal and policy positions in the 2020 Policy Rule would call into question the interpretations of CAA section 111 that the rule included that are noncontroversial and necessary to proper implementation of the provision. There is no reason to think that Congress would have objected to those interpretations, but in any event, this argument by commenters makes clear that the joint resolution's legislative history is useful because it clarifies which interpretations and positions in the rule that Congress did object to.

After reviewing the text of the disapproval and, separately, the disapproval resolution's legislative history, the EPA is proceeding with further rulemaking under CAA section 111 for sources in the Crude Oil and Natural Gas source category. With the 2016 Rule reinstated by the operation of the CRA resolution, the EPA is revising and adding certain NSPS and is promulgating emission guidelines for existing sources. These actions apply to sources in the transmission and storage segment, and apply to methane emissions. This rule is fully consistent with the CRA joint resolution.

VI. Other Actions and Related Efforts

This section of this preamble describes related state actions and other Federal actions regulating oil and natural gas emissions sources; industry and voluntary efforts to reduce methane emissions from this sector; and other EPA programs to reduce methane emissions, including the Methane Emissions Reduction Program that was signed into law as part of the Inflation Reduction of 2022. The final NSPS OOOOb and EG OOOOc include specific measures that build on the experience and knowledge the Agency and industry have gained through voluntary programs and previous regulatory efforts, as well as the leadership of the states in developing their own regulatory programs. The final NSPS OOOOb and EG OOOOc consists of reasonable, proven, cost-effective technologies and practices that reflect the evolutionary nature of the oil and natural gas industry and these proactive regulatory and voluntary efforts.

At the same time, the final NSPS OOOOb and EG OOOOc reflect the EPA's unique authority and responsibility under the CAA to ensure that new and existing sources throughout the nation are subject to appropriate standards of performance through NSPS and approved state plans. By requiring all owners and operators of the sources regulated in this final rulemaking to limit methane emissions, the EPA intends to achieve methane emission reductions on a more consistent and comprehensive basis than has been achieved through current programs and efforts. Direct Federal regulation of methane and VOCs from new sources, combined with approved state plans that are consistent with the EPA's EG for methane from existing sources, will bring national consistency to the regulatory landscape, help promote technological innovation, and reduce both climate- and other health-harming pollution from a large number of sources that are either currently unregulated or where additional cost-effective reductions are available.

A. Related State Actions and Other Federal Actions Regulating Oil and Natural Gas Sources

The EPA recognizes that several states currently regulate emissions from the oil and natural gas industry. The EPA also recognizes that some of these state programs have been expanded and strengthened since the EPA began implementing its 2012 NSPS and subsequent 2016 NSPS. These state-level efforts have been important in spurring the deployment of emission control technologies and practices, and developing a broad base of experience that has informed the final rule. At the same time, the EPA recognizes that state-level regulatory efforts cannot, alone, address the increasingly dangerous impacts of methane emissions on public health and welfare. State agencies regulate in accordance with their own authorities and within their own respective jurisdictions; as a result, there is considerable variation in the scope and stringency of such programs. Collectively, these programs do not fully address the range of sources and emission reduction measures contained in this rulemaking. The EPA is committed to working within its authority to provide opportunities to align its programs with these existing state programs in order to reduce regulatory redundancy where appropriate.

In addition to states, certain Federal agencies also regulate aspects of the oil and natural gas industry pursuant to their own authorities. The EPA has maintained an ongoing dialogue with its Federal partners during the development of this final rulemaking in order to avoid potential regulatory conflicts and unnecessary regulatory obligations on the part of owners and operators as each agency responds to its particular statutory charge.

The below description summarizes other Federal regulations and programs related to air emissions from the oil and natural gas industry. The U.S. Department of the Interior (DOI) regulates the extraction of oil and gas from Federal and Indian lands. DOI bureaus that are responsible for administering natural resources conservation and safety related to onshore and offshore energy development include the Bureau of Land Management (BLM) (Federal onshore fossil fuel related activities), the Bureau of Safety and Environmental Enforcement (Federal offshore safety and environmental protection of oil and gas development), and the Bureau of Ocean Energy Management (BOEM) (Federal offshore oil and gas related activities). The BLM manages the Federal Government's onshore subsurface mineral estate—about 700 million acres (30 percent of the U.S.)—for the benefit of the American public. The BLM maintains the Federal onshore oil and gas leasing program pursuant to the Mineral Leasing Act, the Mineral Leasing Act for Acquired Lands, the Federal Land Management and Policy Act, and the Federal Oil and Gas Royalty Management Act. The BLM's oil and gas operating regulations are found in 43 CFR part 3160. An oil and gas operator's general environmental and safety obligations for onshore activities are found at 43 CFR 3162.5. Pursuant to a delegation of Secretarial authority, the BLM also oversees oil and gas operations on many Indian/Tribal leases.

The BLM has the express authority and responsibility to regulate both for the prevention of waste and the protection of the environment for operations on Federal and Indian lands. This responsibility includes promulgating regulations to reduce the waste of natural gas from oil and gas leases administered by the BLM. This gas is lost during oil and gas exploration and production activities through venting, flaring, and leaks. More detailed information can be found at the BLM's website: https://www.blm.gov/programs/energy-and-minerals/oil-and-gas/operations-and-production/methane-and-waste-prevention-rule.

BOEM manages the development of U.S. Outer Continental Shelf (offshore) energy and mineral resources. BOEM has air quality jurisdiction in the Gulf of Mexico and the North Slope Borough of Alaska. BOEM also has air jurisdiction in Federal waters on the Outer Continental Shelf 3–9 miles offshore (depending on the state) and beyond. The Outer Continental Shelf Lands Act (OCSLA), section 5(a)(8) states, “The Secretary of the Interior is authorized to prescribe regulations `for compliance with the national ambient air quality standards pursuant to the CAA . . . to the extent that activities authorized under [the Outer Continental Shelf Lands Act] significantly affect the air quality of any state.' ” The EPA and states have the air jurisdiction onshore and in state waters, and the EPA has air jurisdiction offshore in certain areas. More detailed information can be found at BOEM's website: https://www.boem.gov/.

The U.S. Department of Transportation (DOT) manages the U.S. transportation system. Within DOT, the Pipeline and Hazardous Materials Safety Administration (PHMSA) is responsible for regulating and ensuring the safe and secure transport of energy and other hazardous materials to industry and consumers by all modes of transportation, including pipelines. While PHMSA regulatory requirements for gas pipeline facilities have focused on human safety, which has attendant environmental co-benefits, the “Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2020” (Pub. L. 116–260, Division R; “PIPES Act of 2020”), which was signed into law on December 27, 2020, revised PHMSA organic statutes to emphasize the centrality of environmental safety and protection of the environment in PHMSA decision making. For example, the PHMSA's Office of Pipeline Safety ensures safety in the design, construction, operation, maintenance, and incident response of the U.S.' approximately 3.3 million miles of natural gas and hazardous liquid transportation pipelines. When pipelines are maintained, the likelihood of environmental releases like leaks are reduced. In addition, the PIPES Act of 2020 contains several provisions that specifically address the minimization of releases of natural gas from pipeline facilities, such as a mandate that the Secretary of Transportation promulgate regulations related to gas pipeline LDAR programs. More detailed information can be found at PHMSA's website: https://www.phmsa.dot.gov/.

The U.S. Department of Energy (DOE) develops oil and natural gas policies and funds research on advanced fuels and monitoring and measurement technologies. Specifically, the Advanced Research Projects Agency-Energy (ARPA–E) program advances high-potential, high-impact energy technologies that are too early for private-sector investment. APRA–E awardees are unique because they are developing entirely new technologies. More detailed information can be found at ARPA–E's website: https://arpa-e.energy.gov/. Also, the U.S. Energy Information Administration (EIA) compiles data on energy consumption, prices, including natural gas, and coal. More detailed information can be found at the EIA's website: https://www.eia.gov/.

The U.S. Federal Energy Regulatory Commission (FERC) is an independent agency that regulates the interstate transmission of electricity, natural gas, and oil. FERC also reviews proposals to build liquefied natural gas terminals and interstate natural gas pipelines, and licenses hydropower projects. FERC's responsibilities for the crude oil industry include the following: regulation of rates and practices of oil pipeline companies engaged in interstate transportation; establishment of equal service conditions to provide shippers with equal access to pipeline transportation; and establishment of reasonable rates for transporting petroleum and petroleum products by pipeline. FERC's responsibilities for the natural gas industry include the following: regulation of pipeline, storage, and liquefied natural gas facility construction; regulation of natural gas transportation in interstate commerce; issuance of certificates of public convenience and necessity to prospective companies providing energy services or constructing and operating interstate pipelines and storage facilities; regulation of facility abandonment, establishment of rates for services; regulation of the transportation of natural gas as authorized by the Natural Gas Policy Act and OCSLA; and oversight of the construction and operation of pipeline facilities at U.S. points of entry for the import or export of natural gas. FERC has no jurisdiction over construction or maintenance of production wells, oil pipelines, refineries, or storage facilities. More detailed information can be found at FERC's website: https://www.ferc.gov/.

B. Industry and Voluntary Actions To Address Climate Change

Separate from regulatory requirements, some owners or operators of facilities in the oil and natural gas industry choose to participate in voluntary initiatives to reduce methane emissions from their operations. Over 100 oil and natural gas companies have participated in the EPA Natural Gas STAR Program and Methane Challenge partnership over the past several decades. Owners or operators also participate in a growing number of voluntary programs unaffiliated with the EPA voluntary programs; the EPA is aware of at least 19 such initiatives. Firms participate in voluntary environmental programs for a variety of reasons, including attracting customers, employees, and investors who value more environmentally-responsible goods and services; finding approaches to improve efficiency and reduce costs; and preparing for or helping inform future regulations.

The EPA's Natural Gas STAR Program started in 1993 with the objective of achieving methane emission reductions through implementation of cost-effective best practices and technologies. Through the program, partner companies documented their voluntary emission reduction activities and reported their accomplishments to the EPA annually. Over the course of the Natural Gas STAR Partnership from 1993 to 2022, the EPA collaborated with over 100 companies across the natural gas value chain. Through the partnership, the EPA tracked more than 150 different methane-reducing activities and technologies which it then shared among partners and through the program website. Between 1993 and 2020, partner companies reported cumulative methane emissions reductions of nearly 1.7 trillion cubic feet.

The EPA's Methane Challenge Program was launched in 2016 to expand upon the Natural Gas STAR Program by providing partner companies the opportunity to make ambitious, quantifiable emissions reduction commitments, provide detailed, transparent reporting, and receive partner recognition. Annually, Methane Challenge Partners submit facility-level reports that characterize methane emission sources at their facilities and detail voluntary actions taken to reduce methane emissions. The EPA emphasizes the importance of transparency by publishing these facility-level data. Since its inception, the Methane Challenge Program has included nearly 70 companies and currently has 54 active partners, primarily from the transmission and distribution segments.

Other voluntary programs for the oil and natural gas industry are administered by numerous organizations, including trade associations and non-profits. These voluntary efforts have helped reduce methane emissions beyond what is required by current regulations, as well as to significantly expand the understanding of methane mitigation measures within the industry and among Federal and state regulators. Although the EPA recognizes and commends the value of these programs, such voluntary efforts are not legally binding and do not alter the EPA's own statutory responsibility to regulate methane emissions from this sector under the CAA. Moreover, as the information and analysis reflected in this final rulemaking make clear, there is still considerable need and opportunity to further reduce methane emissions from the industry.

C. Methane Emissions Reduction Program

In August 2022, Congress passed, and President Biden signed, the Inflation Reduction Act of 2022 into law. Section 60113 of the Inflation Reduction Act of 2022 amended the CAA by adding section 136, “Methane Emissions and Waste Reduction Incentive Program for Petroleum and Natural Gas Systems” (also referred to as the “Methane Emissions Reduction Program”).

Subsections (a) and (b) of CAA section 136 provide $1.55 billion for the Methane Emissions Reduction Program, including for incentives for methane mitigation and monitoring. The EPA is partnering with the DOE and National Energy Technology Laboratory to provide financial assistance for monitoring and reducing methane emissions from the oil and gas sector, as well as technical assistance to help implement solutions for monitoring and reducing methane emissions. As designed by Congress, these incentives were intended to complement the regulatory programs and to help facilitate the transition to a more efficient petroleum and natural gas industry.

On August 1, 2023, the EPA proposed revisions to GHGRP subpart W consistent with the authority and directives set forth in CAA section 136(h), as well as the EPA's authority under CAA section 114 (88 FR 50282). In that rulemaking, the EPA proposed revisions to require reporting of additional emissions or emissions sources to address potential gaps in the total methane emissions reported by facilities to GHGRP subpart W. For example, these proposed revisions would add a new emissions source, referred to as “other large release events,” to capture large emissions events that are not accurately accounted for using existing methods in GHGRP subpart W. The EPA also proposed revisions to add or revise existing calculation methodologies to improve the accuracy of reported emissions, incorporate additional empirical data, and allow owners and operators of applicable facilities to submit empirical emissions data that could appropriately demonstrate the extent to which a charge is owed in implementation of CAA section 136, as directed by CAA section 136(h). The EPA also proposed revisions to existing reporting requirements to collect data that would improve verification of reported data, ensure accurate reporting of emissions, and improve the transparency of reported data. Additionally, the EPA proposed revisions that would align GHGRP subpart W with other EPA programs and regulations, including proposing revisions to certain requirements in GHGRP subpart W relative to the requirements proposed for NSPS OOOOb and the presumptive standards proposed in EG OOOOc (such that, as applicable, facilities would use a consistent method to demonstrate compliance with multiple EPA programs once their emission sources are required to comply with either the final NSPS OOOOb or an approved state plan or applicable Federal plan in 40 CFR part 62).

CAA section 136(c) directs the Administrator of the EPA to “impose and collect a charge on methane emissions that exceed an applicable waste emissions threshold under subsection (f) from an owner or operator of an applicable facility that reports more than 25,000 metric tons of carbon dioxide equivalent (CO₂ Eq.) of GHG emitted per year pursuant to subpart W of part 98 of title 40 (40 CFR part 98), regardless of the reporting threshold under that subpart” (hereinafter, waste emissions charge). An “applicable facility” is defined under CAA section 136(d) to include nine specific industry segments as defined in GHGRP subpart W. Pursuant to CAA section 136(g), the waste emissions charge “shall be imposed and collected beginning with respect to emissions reported for calendar year 2024 and for each year thereafter.”

CAA section 136(f) includes specific exemption from the waste emissions charge for certain applicable facilities that meet certain criteria, including what the EPA refers to as a “regulatory compliance exemption.” Specifically, CAA section 136(f)(6)(A) states that “charges shall not be imposed pursuant to subsection (c) on an applicable facility that is subject to and in compliance with methane emissions requirements pursuant to subsections (b) and (d) of section 111 upon a determination by the Administrator that: (i) Methane emissions standards and plans pursuant to subsections (b) and (d) of section 111 have been approved and are in effect in all states with respect to the applicable facilities; and (ii) compliance with the requirements described in clause (i) will result in equivalent or greater emissions reductions as would be achieved by the proposed rule of the Administrator entitled `Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review' (86 FR 63110; (November 15, 2021), if such rule had been finalized and implemented.” Per CAA section 136(f)(6)(B), “if the conditions in clause (i) or (ii) of subparagraph (A) cease to apply after the Administrator has made the determination in that subparagraph, the applicable facility will again be subject to the charge under subsection (c) beginning in the first calendar year in which the conditions in either clause (i) or (ii) of that subparagraph are no longer met.”

In the preamble to the December 2022 Supplemental Proposal, the EPA noted that implementation of CAA section 136 was outside the scope of the present rulemaking, and that the EPA intended to take one or more separate actions in the future to implement CAA section 136. However, the EPA requested comment on the criteria and approaches that the Administrator should consider in making the CAA section 136(f)(6)(A)(ii) “equivalency determination” in such separate future action. Consistent with our statements in the December 2022 Supplemental Proposal, the EPA is not taking any final actions to implement CAA section 136 in this action and these comments are therefore outside the scope of this final rule.

VII. Summary of Engagement With Pertinent Stakeholders

As part of the regulatory development process for this rulemaking, the EPA conducted extensive outreach with the public, states, Tribal nations, and a broad range of pertinent stakeholders in order to gather information from a variety of viewpoints. This engagement allowed the EPA to provide stakeholders with overviews of the November 2021 Proposal and the December 2022 Supplemental Proposal, and to explain to the public and pertinent stakeholders how to effectively engage in the regulatory process. Such outreach is consistent with several E.O.s that encourage the Federal government to have a robust public participation process in regulatory development, particularly for communities with EJ concerns. The EPA specifically identified a long list of stakeholders with which to engage throughout the rulemaking process—including, but not limited to, industry, small businesses, Tribal nations, and communities most affected by, and vulnerable to, the impacts of the rule.

Prior to the November 2021 Proposal, the EPA opened a public docket for pre-proposal input. Throughout the rulemaking, the EPA engaged with pertinent stakeholders likely to be interested in this rulemaking in several ways, including through meetings, training webinars, round tables, public listening sessions, and a technical workshop. For example, the EPA hosted a two-part webinar training specifically targeted toward both communities with EJ concerns and Tribal nations on November 16 and 17, 2021. The purpose of this training event was for the EPA to facilitate stakeholder panel discussions and to provide background information and an overview of the November 2021 Proposal, as well as information on how to effectively engage in the regulatory process. Subsequently, on November 14, 2022, the EPA hosted a call for environmental groups and EJ communities; on November 17, 2022, the EPA held a webinar for both members of Tribal nations and communities; and on November 30, 2022, the EPA held a training for Tribal Environmental Professionals. In a second example, the EPA held a training for small businesses on May 25, 2021, November 18, 2021, and November 30, 2022, that provided an overview of how the oil and natural gas industry is regulated and offered information on how to participate in the rulemaking process. In a third example, the EPA held calls with the Association of Air Pollution Control Agencies and the National Association of Clean Air Agencies on December 6, 2022, and December 14, 2022. In addition, on November 14, 2022, the EPA held a meeting with industry and labor groups to provide an overview of the proposed supplemental changes to the rulemaking. Throughout the rulemaking process the EPA has met individually with hundreds of industry representatives, NGOs, technology vendors, academics, data companies, and others. The EPA held 3-day virtual public hearings for all stakeholders on both the November 2021 Proposal and the December 2022 Supplemental Proposal.

The EPA notes that the implementing regulations (40 CFR part 60, subpart Ba) require states to include a description of how they have engaged with pertinent stakeholders in the development of their state plans implementing the EG in their state plan submission to the EPA (to implement EG OOOOc). The EPA has led by example and demonstrated various examples of engagement with pertinent stakeholders so that states—while not limited by the EPA's outreach examples—will have a model for how they can structure their own outreach. For additional discussion on meaningful engagement as related to the development of state plans implementing the EG, please see section XIII.C.6 of this preamble.

VIII. Overview of Control and Control Costs

A. Control of Methane and VOC Emissions in the Crude Oil and Natural Gas Source Category—Overview

As described in the November 2021 Proposal and the December 2022 Supplemental Proposal, the EPA reviewed the standards in the 2012 NSPS OOOO and 2016 NSPS OOOOa pursuant to CAA section 111(b)(1)(B). Based on this review, the EPA is finalizing revisions to the standards for a number of affected facilities to reflect the updated BSER for those affected facilities. Where our analyses show that the BSER for an affected facility remains the same, the EPA is finalizing to retain the current standard for that affected facility. In addition to the review of the existing standards, the EPA is finalizing new standards for GHGs (in the form of limitation on methane) and VOCs for some sources that were previously unregulated under NSPS OOOO and NSPS OOOOa. The NSPS OOOOb would apply to new, modified, and reconstructed emission sources across the Crude Oil and Natural Gas source category for which construction, reconstruction, or modification is commenced after December 6, 2022.

Further, pursuant to CAA section 111(d), the EPA is finalizing EG, which include presumptive standards for GHGs (in the form of limitations on methane) (designated pollutant), for certain existing emission sources across the Crude Oil and Natural Gas source category in EG OOOOc. While the requirements in NSPS OOOOb would apply directly to new sources, the requirements in EG OOOOc are for states to use in the development of plans that establish standards of performance that will apply to existing sources (designated facilities).

B. How does the EPA evaluate control costs in this final action?

Section 111 of the CAA requires the EPA to consider a number of factors, including cost, in determining “the best system of emission reduction . . . adequately demonstrated.” CAA section 111(a)(1). The D.C. Circuit has long recognized that “[CAA] section 111 does not set forth the weight that [ ] should [be] assigned to each of these factors;” therefore, “[the court has] granted the agency a great degree of discretion in balancing them.” Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 1999). The courts have recognized that the EPA has “considerable discretion under [CAA] section 111,” id., on how it considers cost under CAA section 111(a)(1). As the Supreme Court has more recently noted, “[i]t will be up to the Agency to decide (as always, within the limits of reasonable interpretation) how to account for cost.” Michigan v. EPA, 576 U.S. 743, 759 (2015). A more detailed description of relevant case law guiding the EPA's consideration of costs is set forth in section IV.A of this document and in the November 2021 Proposal. See 86 FR at 63133, 63154 (November 15, 2021). For the purposes of this final rule, we use the term “reasonable” to describe costs which, based on our evaluation, are considered to be well within the boundaries of our discretion granted by Congress and recognized by the courts.

As explained in further detail below, the EPA has determined that the costs of controls associated with the BSER for the final NSPS OOOOb and EG OOOOc are reasonable. In reaching this determination, the EPA conducted numerous cost analyses, described in detail in section XII of the November 2021 Proposal, Section IV of the December 2022 Supplemental Proposal, and section XI of this preamble—all of which discuss the BSER determinations for each of the regulated emissions sources—and in the final rule TSD in the docket for this rulemaking.

In evaluating whether the cost of a control is reasonable, the EPA considers various associated costs, including capital costs and operating costs, when evaluating the BSER for each emission source. In addition, as discussed further below, the Agency considered the costs of the collective standards for the final NSPS OOOOb and EG OOOOc in the context of the industry's overall capital expenditures and revenues. As discussed in more detail below, the capital expenditures in pollution control estimated to result from this rulemaking represent 2–3 percent of the industry's annual capital expenditures. The estimated total annual expenditures represent less than one percent of the industry's annual revenue. Neither estimate includes increased industry revenue from the sales of captured gas resulting from pollution controls, which offsets some of these costs. At the same time, this rulemaking is estimated to reduce 58 million short tons of methane from 2024 to 2038—representing a 79 percent reduction in projected emissions from the sources covered in this rulemaking.

As discussed in more detail in the November 2021 Proposal, see 86 FR 63154–7 (November 15, 2021), the EPA also considers a cost effectiveness analysis to be a useful metric, as it provides a means of evaluating whether a given control achieves emissions reduction at a reasonable cost and allows comparisons of relative costs and outcomes (effects) of two or more options. Cost effectiveness also provides a means of assessing consistency across rules regulating, and sectors regulated for, the same pollutant. In the context of an air pollution control option, cost effectiveness typically refers to the annualized cost of implementing an air pollution control measure divided by the amount of pollutant reductions realized annually. Notably, a cost effectiveness analysis is not intended to constitute or approximate a benefit-cost analysis in which monetized benefits are compared to costs, but rather is intended to provide a metric to compare the relative cost of emissions reductions. As explained in further detail in the November 2021 Proposal and the December 2022 Supplemental Proposal, the EPA estimated the cost effectiveness values of the various control options assessed for this rulemaking using the best information available to the Agency. The sources upon which the EPA relied in assessing cost effectiveness are described in detail in the TSDs and include studies by academia, non-governmental organizations, and state and Federal agencies. The EPA also relied upon costs and emissions data, as well as information related to technical limitations, submitted by members of the affected industry, including oil and gas production companies, and control device vendors and numerous other stakeholders, in the form of public comments in this rulemaking and previous rulemakings. The EPA also relied upon financial information provided by industry organizations that represent small businesses, such as the Michigan Oil & Gas Association (MOGA).

The EPA used two approaches to determine cost effectiveness in this rulemaking. The first approach—the “single-pollutant cost effectiveness approach”—assigns all costs to the emission reduction of one pollutant and zero costs to all other concurrent reductions; where the cost of the control is reasonable for reducing any of the targeted pollutants alone, the cost is reasonable for all concurrent emissions reductions (because these additional pollutants are reduced at no additional cost). The second approach—the “multipollutant cost effectiveness approach”—apportions annualized cost of all pollutant reductions achieved by the control option in proportion to the relative percentage reduction of each pollutant controlled. A more detailed explanation of these approaches is set forth at 86 FR 63154–56 (November 15, 2021) and 87 FR 74718–19 (December 6, 2022).

As such, in the individual BSER analyses set forth in further detail section XII of the November 2021 Proposal, Section IV of the December 2022 Supplemental Proposal, and section XI of this preamble, for each control required in the final NSPS OOOOb, if a device is cost-effective under either of these two approaches, it is considered cost-effective. For EG OOOOc, which regulates only methane, a control is considered reasonable if it is cost-effective under the single-pollutant cost effectiveness approach. In addition to evaluating the annual average cost effectiveness of a control option, the EPA also considered the incremental costs associated with increasing the stringency of emissions standards in determining the appropriate level of stringency. See 86 FR 63156 (November 15, 2021) and 87 FR 74718–19 (December 6, 2022) for further details on incremental cost effectiveness analysis.

The EPA provides the cost effectiveness estimates for reducing VOC and methane emissions for various control options considered in the November 2021 Proposal and the December 2022 Supplemental Proposal, as well as in section XI of this preamble and associated TSDs. With respect to VOC emissions, the EPA finds that cost effectiveness values up to $5,540/ton of VOC reduction are reasonable for controls that we have identified as BSER in the final NSPS OOOOb and EG OOOOc. These VOC values are within the range of what the EPA has historically considered to represent cost-effective controls for the reduction of VOC emissions, including in the 2016 NSPS, based on the Agency's long history of regulating a wide range of industries.

For methane, the 2016 NSPS OOOOa was the first national standard for reducing methane emissions. Accordingly, at that time, the EPA considered a variety of information in evaluating whether the costs of control that would be imposed by the final NSPS and presumptive EG standards in this action are reasonable. As discussed in the November 2021 Proposal, the EPA previously determined that methane cost effectiveness values for the controls identified as BSER for the 2016 NSPS OOOOa, which ranged up to $2,185/ton of methane reduction, represent reasonable costs for the industry as a whole to bear to reduce pollution. 86 FR 63155 (November 15, 2021). The reasonableness of the methane value selected in that rulemaking is reinforced by the fact that sources have been complying with the 2016 NSPS OOOOa for years without deleterious effect on the industry as a whole, which indicates that the NSPS OOOOa standards are not unduly burdensome from a cost perspective. The final standards in this rulemaking similarly reflect control mechanisms and measures that many companies and sources around the country are already implementing—again, without deleterious effect on industry as a whole—which shows not only that such controls are “adequately demonstrated” but also underscores their reasonableness from a cost perspective. For methane, the controls that we have identified as BSER in the final NSPS OOOOb and EG OOOOc to be reasonable at cost-effectiveness values up to $2,048/ton of methane reduction. The fact that the cost effectiveness estimates for the final standards in this action are comparable to (and in many individual instances, lower than) the cost effectiveness values estimated for the controls that served as the basis ( i.e., BSER) for the standards in the 2016 NSPS OOOOa, which have been in place for years, reinforces the conclusion that the final NSPS and presumptive standards in this rule are also cost-effective and reasonable.

As explained in further detail in the November 2021 Proposal, when determining the overall costs of implementation of the control technology and the associated cost effectiveness, the EPA takes into account cost savings from any natural gas recovered instead of vented as a result of the emissions controls. In our analysis, we consider any natural gas that is either recovered or not emitted as a result of a control option as being “saved;” we then apply the monetary value of the saved natural gas (estimated at $3.13 per Mcf), as an offset to the control cost. Notably, this offset does not apply where the owner or operator does not own the gas and would not likely realize the monetary value of the natural gas saved ( e.g., transmission stations and storage facilities). Detailed discussions of this approach are presented in section 2 of the RIA and at 86 FR 63156 (November 15, 2021).

We also updated the two additional analyses that the EPA performed for both the November 2021 Proposal and the December 2022 Supplemental Proposal to further inform our determination of whether the cost of control of the collection of standards would be reasonable, similar to compliance cost analyses we have completed for other NSPS. The two additional analyses include: (1) a comparison of the capital costs incurred by compliance with the rulemaking to the industry's estimated new annual capital expenditures, and (2) a comparison of the annualized costs that would be incurred by compliance with the final NSPS and presumptive EG standards to the industry's estimated annual revenues. In this section, the EPA provides updated information regarding these cost analyses based on the standards described in this document. See 86 FR 63156–7 (November 15, 2021) and 87 FR 74718–19 (December 6, 2022) for additional discussion on these two analyses. The results of both analyses, described in more detail in the following paragraphs, each independently demonstrate the reasonableness of the cost-effectiveness values applied in this final NSPS OOOOb and EG OOOOc, as well as demonstrate that the collective costs of the suite of final standards are reasonable in the context of the industry as a whole.

First, for the capital expenditures analysis, the EPA divided the nationwide capital expenditures projected to be spent to comply with the standards finalized in this rulemaking by an estimate of the total sector-level new capital expenditures for a representative year; this calculation shows the percentage that the nationwide capital cost requirements under the final standards represent of the total capital expenditures by the sector. The EPA combined the compliance-related capital costs under the final standards for NSPS OOOOb and for the presumptive standards in the final EG OOOOc in order to analyze the potential aggregate impact of the rulemaking. The equivalent annualized value (EAV) of the projected compliance-related capital expenditures over the 2024 to 2038 period is projected to be about $2.5 billion in 2019 dollars. We obtained new capital expenditure data for relevant NAICS codes for 2018–2021 from the 2019, 2020, and 2021 editions of the U.S. Census Annual Capital Expenditures Survey. According to these data, new capital expenditures for the sector ranged from $79 billion in 2021 to $156 billion in 2019 w in 2019 dollars. The wide range of annual expenditures across years are likely due to COVID–19-related impacts that dampened spending in 2020 and 2021. As such, while we conducted the analysis for all years from 2018 to 2021, we view the results for 2018 and 2019 as more representative of expected industry outlays going forward. Note that new capital expenditures in 2019 for pipeline transportation of natural gas (NAICS 4862) includes only expenditures on structures because data on equipment expenditures are withheld to avoid disclosing data for individual enterprises. As a result, the 2019 capital expenditures used here represent an underestimate of the sector's expenditures. Comparing the EAV of the projected compliance-related capital expenditures under this rule with the 2019 total sector-level new capital expenditures yields a percentage of about 1.6 percent, which is well below the percentage increase previously upheld by the courts as reasonable under CAA section 111. See detailed discussion at 86 FR 63156–7 (November 15, 2021) (citing Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 437–40 (D.C. Cir. 1973); Portland Cement Ass'n v. Train, 513 F.2d 506, 508 (D.C. Cir. 1975)). The same comparison for 2021 total sector-level new capital expenditures yields a percentage of about 3.2 percent.

Second, for the comparison of compliance costs to revenues, we used the EAV of the projected compliance costs both with and without projected revenues from product recovery under the rule for the 2024 to 2038 period, then divided the nationwide annualized costs by the annual revenues for the appropriate NAICS code(s) for a representative year in order to determine the percentage that the nationwide annualized costs represent of annual revenues. Like we do for capital expenditures, we combine the costs projected to be expended to comply with the standards for NSPS and the presumptive standards in the EG in order to analyze the potential aggregate impact of the rule. The EAV of the associated increase in compliance cost over the 2024 to 2038 period is projected to be about $2.7 billion without revenues from product recovery and about $1.7 billion with revenues from product recovery (in 2019 dollars). Revenue data for relevant NAICS codes were obtained from the U.S. Census 2017 County Business Patterns and Economic Census, the most recent revenue figures available. According to these data, 2017 receipts for the sector were about $357 billion in 2019 dollars. Comparing the EAV of the projected compliance costs under the rulemaking with the sector-level receipts figure yields a percentage of about 0.8 percent without revenues from product recovery and about 0.5 percent with revenues from product recovery. More data and analysis supporting the comparison of capital expenditures and annualized costs projected to be incurred under the rule and the sector-level capital expenditures and receipts is presented in the TSD for this action, which is in the public docket.

Based on all of the cost-related information, data, and analyses described above, and as explained in further detail in the individual sections describing the BSER for each control in this preamble, the November 2021 Proposal, and the December 2022 Supplemental Proposal, the EPA concludes that the costs of the controls that serve as the basis the final NSPS OOOOb and EG OOOOc are reasonable.

Some commenters have argued that the EPA was required to perform a cost-benefit analysis of this rulemaking demonstrating that the costs outweigh the benefits, and have cited the Supreme Court's decision in Michigan v. EPA, 576 U.S. 743 (2015) in support of this contention. One commenter contends that the EPA's proposal is not reasonable if the climate benefits are illusory, and questions “[w]hat benefit-cost calculation makes the proposed regulatory surge a smart investment of public and private resources.” The commenter also takes issue with the EPA's statement in the Supplemental Proposal that our “monetized benefits analysis is entirely distinct from the statutory BSER determinations proposed herein and is presented solely for the purposes of complying with E.O. 12866,” 87 FR 74843. The commenter cites one excerpt from the Supreme Court's decision Michigan in support of its argument: “One would not say that it is even rational, never mind `appropriate,' to impose billions of dollars in economic costs in return for a few dollars in health or environmental benefits . . . No regulation is `appropriate' if it does significantly more harm than good.” 576 U.S. at 752. Another group of commenters quotes the same language from the case and asserts that the EPA must “balance the costs associated with government regulation against compliance costs,” and that the November 2021 Proposed Rule “fails the cost-benefits test.”

The EPA is mindful of the Supreme Court's holding in Michigan and has carefully considered how it applies to this rulemaking. The EPA disagrees with the commenters insofar as they suggest that the EPA was required—under Michigan or any other authority—to undertake a formal cost-benefit analysis in this rulemaking. In Michigan, the Supreme Court concluded that the EPA erred when it concluded it could not consider costs when deciding whether it is “appropriate and necessary” under CAA section 112(n)(1)(A) to regulate hazardous air pollutants from electric utility steam generating units (power plants), despite the relevant statutory provision containing no specific reference to cost. 576 U.S. at 751. In doing so, the Court held that the EPA “must consider cost—including, most importantly, cost of compliance—before deciding whether regulation is appropriate and necessary” under CAA section 112. Id. at 759. In examining the language of CAA section 112(n)(1)(A), the Court concluded that the phrase “appropriate and necessary” was “capacious” and held that “[r]ead naturally in the present context, the phrase `appropriate and necessary' requires at least some attention to cost.” Id. at 752. This capaciousness was relevant in the context of section 112(n)(1)(A) because that section directs the EPA to determine “ whether to regulate” the emission source, which is a context in which “[a]gencies have long treated cost as a centrally relevant factor.” Id. at 753 (emphasis added).

The Supreme Court added in Michigan that it “need not and [does] not hold that the law unambiguously required the Agency, when making this preliminary estimate [of costs under the `appropriate and necessary' standard of CAA 112(n)(a)(1)], to conduct a formal cost-benefit analysis in which each advantage and disadvantage is assigned a monetary value. It will be up to the Agency to decide (as always, within the limits of reasonable interpretation) how to account for cost.” Id. at 759.

Section 111 differs in material respects from the provision the Supreme Court interpreted in Michigan. Unlike the circumstances at issue in Michigan, the predicate decision whether to regulate the emission source has already been made here. CAA section 111(b)(1)(A) requires the Administrator to list a source category “if, in his judgment, it causes or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare.” Notably, this provision does not hinge on a determination, like that under consideration in Michigan with respect to CAA section 112, that such listing is “appropriate and necessary.” Indeed, the EPA has long regulated emissions from the oil and gas source category, having first listed the source category in 1979. And once the EPA has listed a source category, CAA section 111(b)(1)(B) and (d)(1) require the EPA to promulgate new source performance standards and, for certain pollutants, emission guidelines for regulation of existing sources. Pursuant to this authority, the EPA has regulated VOC emissions since 1985 and GHG emissions (in the form of limitations on methane) since 2016. See section IV.B for further explanation of the regulatory history for the source category; and section V for further discussion of the EPA's authority to promulgate methane regulations.

Importantly, unlike the statutory provision at issue in Michigan, CAA section 111 already requires the EPA to consider costs when determining the appropriate level of control. Specifically, the “standards of performance” for new and existing sources finalized in this rule are “standard[s] for emissions of air pollutants which reflect[] the degree of emission limitation achievable through the application of the best system of emission reduction which ( taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated.” CAA section 111(a)(1) (emphasis added). Thus, even if the Court's examination of CAA 112(n)(a)(1) in Michigan did apply to CAA section 111—which the EPA disputes—the EPA's decision here, unlike in the rule reviewed in Michigan, is not blind to costs. Rather, the EPA has satisfied the Court's directive to consider costs, both in the context of the individual BSER analyses for individual emissions source (as directed by the language of the statute) and in the context of the rule as a whole. Moreover, while the EPA is not required to undertake a “formal cost-benefit analysis in which each advantage and disadvantage [of a regulation] is assigned a monetary value,” Michigan, 576 U.S. at 759, the EPA has contemplated and carefully considered both the advantages and disadvantages of the final NSPS OOOOb and EG OOOOc, including the qualitative and quantitative benefits of the regulation and the costs of compliance.

The primary disadvantage that the EPA has weighed in finalizing the NSPS OOOOb and EG OOOOc is the cost of compliance and the effects of those costs on industry. Notably, neither CAA section 111 nor Michigan directs that costs be considered in any particular way, and in this action, the EPA has considered costs using the same cost metrics that the EPA has historically used in numerous rulemakings under CAA section 111 for decades. As explained above, the EPA has used cost effectiveness as a metric to evaluate whether the costs associated with emissions reductions from a given technology are reasonable. This metric (widely used in environmental regulation) provides a way for the EPA to specifically consider the cost associated with each ton of reduction achieved by a particular control measure, and thereby determine whether the emission reductions achieved by the control measure are worthwhile, both as to the individual control measure in comparison to other available control measures, and in comparison to the regulation of the same pollutant in other industries. As explained in detail in section XI of this preamble, section XII of the November 2021 Proposal, and Section IV of the December 2022 Supplemental Proposal discussing the BSER determinations for each of the regulated emissions sources, the EPA has also considered costs in various other ways, including capital costs and operating costs, when evaluating the reasonableness of various control measures to determine the BSER.

In addition, the EPA conducted two cost analyses specifically for purposes of this action in order to evaluate the costs of compliance with the collective standards in the final NSPS OOOOb and EG OOOOc at a sector level and consider them in the context of the industry's overall capital expenditures and revenues. As explained in detail above, the EPA estimates that the capital costs expected to be incurred by compliance with the final NSPS OOOOb and EG OOOOc are about two to three percent of the industry's estimated new annual capital expenditures, and that the annualized compliance costs are less than one percent of the industry's estimated annual revenues. Notably, neither value includes increased industry revenue from the sales of captured gas resulting from pollution controls. Thus, while the industry will bear some costs to comply with the final NSPS OOOOb and EG OOOOc, each of these analyses supports the EPA's determination that the costs associated with compliance with the final standards are reasonable and consistent with costs of control that the source category has expended for years to comply with existing state and Federal standards, and on voluntary actions to reduce emissions.

In terms of advantages, the final NSPS OOOOb and EG OOOOc will have numerous benefits to the climate, the natural environment, and human health through their projected reductions in methane and VOC emissions. Regarding methane, the oil and natural gas sector is the largest source of industrial methane emissions in the U.S. As described in greater detail in section III.B.2, it represents 28 percent of U.S. anthropogenic methane emissions and three percent of overall U.S. GHG emissions. Moreover, methane is a powerful and potent GHG—over a 100-year timeframe, it is nearly 30 times more powerful at trapping climate warming heat than CO₂, and over a 20-year timeframe, it is 83 times more powerful. Because it is particularly potent and emitted in large quantities, methane mitigation provides one of the best opportunities to reduce near-term warming and offers important climate benefits.

The projected methane emissions reductions from the final NSPS OOOOb and EG OOOOc standards, for each regulated emission source and taken together as a whole, will contribute to avoided climate and human health impacts, which are described in greater detail in section III.A.1 of this preamble, as well as in section III.A of the November 2021 Proposal. Warming temperatures in the atmosphere, ocean, and land have led to, for example: increased numbers of heat waves, wildfires, and other severe weather events; reduced air quality; more intense hurricanes and rainfall events; and sea level rise. These environmental changes, along with future projected changes, endanger the physical survival, health, economic well-being, and quality of life of people living in the U.S., particularly those in the most vulnerable communities. As discussed in greater detail in section III.A.1, impacts from climate change driven by GHG emissions are wide-ranging in type and scope, and present serious threats to human life and the natural environment. For example, severe weather events and natural disasters exacerbated by climate change—such as droughts, floods, storm surges, wildfires, and heat waves—affect food security, air quality and respiratory health, availability of fresh drinking water, population stability, national security, participation in the workforce, and infrastructure and property, among many others. Other environmental impacts of climate change such as ocean acidification, altered plant growth, and increased concentrations of ozone also affect human health and well-being, in addition to that of the natural environment.

The final NSPS OOOOb and EG OOOOc standards are projected to reduce 58 million short tons of methane emissions from 2024 to 2038, which represents a 79 percent reduction in projected emissions from the sources covered in NSPS OOOOb and EG OOOOc. Accordingly, significantly reducing emissions of methane from the largest U.S. industrial source of this highly potent GHG will have meaningful climate benefits and environmental impacts, which will in turn have beneficial impacts on human health.

As described in more detail in section III.A.2, reducing VOC emissions will also benefit human health and the environment. The oil and natural gas sector represents the top anthropogenic U.S. sector for VOC emissions (after removing the biogenics and wildfire sectors), which is about 23 percent of total VOCs emitted by U.S. anthropogenic sources. See section III.B.2. VOCs can cause a variety of health concerns, including cancerous and noncancerous illnesses, particularly respiratory and neurological ones. VOCs are also one of the key precursors in the formation of ozone. Tropospheric, or ground-level, ozone is formed through reactions of VOC and NOx in the presence of sunlight; ozone formation can be controlled to some extent through reductions in emissions of the ozone precursors VOC and NOx. Health effects of ozone exposure include premature death from lung or heart diseases, as well as harmful symptoms and the development of asthma. Repeated exposure to ozone can also have harmful effects on sensitive plants and trees, which have the potential to impact ecosystems and the services they provide. The final NSPS OOOOb and EG OOOOc standards are projected to reduce 16 million short tons of VOC emissions from 2024–2038, which represent a 47 percent reduction in projected emissions from the sources covered in NSPS OOOOb and EG OOOOc. Significant reductions in VOCs, like methane reductions, will have significant benefits to human health and the environment.

In consideration of all of this information, the EPA has concluded that, based on the totality of circumstances, the advantages that the rule provides—namely in the form of a substantial and meaningful reduction in methane and VOC pollution, and the associated positive impacts on public health and the natural environment (as discussed in detail in Section III.A)—outweigh its disadvantages, namely cost of industry compliance in the context of the industry's revenue and expenditures.

IX. Interaction of the Rules and Response to Significant Comments Thereon

A. What date defines a new, modified, or reconstructed source for purposes of the final NSPS OOOOb?

NSPS OOOOb would apply to all emissions sources (“affected facilities”) identified in the final 40 CFR 60.5365b that commenced construction, reconstruction, or modification after December 6, 2022.

Pursuant to CAA section 111(b), the EPA proposed NSPS for a wide range of emissions sources in the Crude Oil and Natural Gas source category in November 2021. Some of the proposed standards resulted from the EPA's review of the current NSPS codified at 40 CFR part 60 subpart OOOOa, while others were proposed standards for additional emissions sources that are currently unregulated. The emissions sources for which the EPA proposed standards in the November 2021 Proposal are as follows:

• Well completions
• Gas well liquids unloading operations
• Associated gas from oil wells
• Wet seal centrifugal compressors
• Reciprocating compressors
• Process controllers
• Pumps
• Storage vessels
• Collection of fugitive emissions components at well sites, centralized production facilities, and compressor stations
• Equipment leaks at natural gas processing plants
• Sweetening units

The EPA proposed standards for an additional emissions source, specifically dry seal centrifugal compressors, in the December 2022 Supplemental Proposal, while also providing numerous significant updates to the standards previously proposed in the November 2021 Proposal.

These final standards of performance apply to “new sources.” CAA section 111(a)(2) defines a “new source” as “any stationary source, the construction or modification of which is commenced after the publication of regulations (or, if earlier, proposed regulations) prescribing a standard of performance under this section which will be applicable to such source.” While the initial rulemaking proposing the standards for these emission sources was published November 15, 2021, due to many significant updates included in the December 2022 Supplemental Proposal, and the addition of dry seal centrifugal compressor proposed standards, the EPA is specifying that the “new sources” to which the final standards in NSPS OOOOb apply are those that commenced construction, reconstruction, or modification after December 6, 2022 (the date the supplemental proposal published in the Federal Register ).

We received comments on the November 2021 Proposal that the proposal lacked regulatory text and therefore should not be used to define new sources for purposes of NSPS OOOOb. The EPA disagrees that absence of a regulatory text in a proposal necessarily means that sources constructed after the date of the proposal cannot be “new sources” for purposes of an NSPS. Regardless, based on the unique facts and circumstances here, the EPA has concluded that only sources constructed, modified, or reconstructed after the date of the supplemental proposal should be considered new sources for the purposes of NSPS OOOOb.

On the unique facts and circumstances here, defining new sources based on the date of the supplemental proposal is consistent with CAA section 111(a)(2). That provision does not require the EPA to define new sources based on the date of the first proposal. Instead, CAA section 111(a)(2) states that a new source is “any stationary source, the construction or modification of which is commenced after the publication of regulations (or, if earlier, proposed regulations) prescribing a standard of performance under this section which will be applicable to such source.” The statute's general reference to “proposed regulations” gives the EPA discretion to determine which proposal (either an initial proposal or a supplemental proposal) should be used to define the universe of new sources in appropriate circumstances. For the reasons stated above, it is reasonable based on the facts and circumstances of this rule to define the date for NSPS OOOOb based on the date of the supplemental proposal. These facts and circumstances include that the supplemental proposal included several updates to the proposed standards and rationale supporting those standards for many different sources, and that the supplemental proposal included new standards for a new source of emissions not addressed by the initial proposal. For example, in the December 2022 Supplemental Proposal, the EPA proposed changes to the proposed standards for fugitives at well sites, the use of alternative monitoring approaches for fugitives, pumps, and standards for dry seal centrifugal compressors. Having potentially differing dates for various new sources ( e.g., one date for sources that the EPA did not propose changes in the December 2022 Supplemental Proposal and another date for sources that the EPA did propose changes to in the December 2022 Supplemental Proposal) that could be within the same facility would complicate the due dates for annual reporting. Having the same date for all sources at a facility will reduce burden on owners and operators to be able to have all annual reporting due simultaneously. Taken together, these facts support establishing the definition of new sources for purposes of NSPS OOOOb as those sources for which construction, modification, or reconstruction commenced after the date of the supplemental proposal.

Moreover, defining new sources as the EPA has described allows the EPA to establish a single new source definition for all NSPS OOOOb, which will streamline administration of the program for states and for the EPA. Because the supplemental proposal included proposed standards for certain sources not addressed in the initial proposal, if the EPA set the definition for new sources for NSPS OOOOb based on the dates upon which each of the standards were first proposed for each emissions source, the new source definition would run from the date of initial proposal for some sources of emissions, and the date of the supplemental proposal for others. Put another way, under that scenario, NSPS OOOOb would contain multiple definitions of “new source” which would differ from standard to standard. This complexity could make administration of the NSPS OOOOb unnecessarily cumbersome. Moreover, the time between the original November 2021 Proposal and the December 2022 Supplemental Proposal was not vast. Within this single year, the EPA believes that a relatively modest number of sources commenced construction. While moving the applicability date for NSPS OOOOb does mean that these sources which commenced construction between the November 2021 Proposal and the December 2022 Supplemental Proposal will be considered “existing sources” for purposes of EG OOOOc instead of “new sources” under NSPS OOOOb, the EPA believes that this is an acceptable and preferred outcome when compared to the complexities associated with the alternative which are explained above. Notably, the EPA is also finalizing existing source EG in this action, which will ultimately require these sources to comply with standards of performance adopted in state plans under EG OOOOc.

B. What date defines an existing source for purposes of the final EG OOOOc?

The November 2021 Proposal and December 2022 Supplemental Proposal also included proposed emissions guidelines for states to follow to develop plans to regulate existing sources in the Crude Oil and Natural Gas source category under EG OOOOc. Under CAA section 111, relative to a particular NSPS, a source is considered either new, i.e., construction, reconstruction, or modification commenced after a proposed NSPS is published in the Federal Register (CAA section 111(a)(2)), or existing, i.e., any source other than a new source (CAA section 111(a)(6)). Accordingly, any source that is not subject to the proposed NSPS OOOOb as described is an existing source for purposes of EG OOOOc. As explained, the EPA is finalizing that for purposes of NSPS OOOOb new sources are those that commenced construction, reconstruction, or modification after December 6, 2022. Therefore, existing sources are those that commenced construction, reconstruction, or modification on or before December 6, 2022.

C. How will the final EG OOOOc impact sources already subject to NSPS KKK, NSPS OOOO, or NSPS OOOOa?

Sources currently subject to 40 CFR part 60, subpart KKK (NSPS KKK), 40 CFR part 60, subpart OOOO, or NSPS OOOOa would continue to comply with their respective VOC and methane standards until sources are subject to and in compliance with a state or Federal plan implementing EG OOOOc. While EG OOOOc specifically addresses methane and not VOC, any reductions from the methane standards established in a state or Federal plan implementing EG OOOOc will similarly reduce VOCs. Therefore, the EPA concludes that the methane presumptive standards in EG OOOOc will result in the same or greater emission reductions than the VOC and methane standards in previous NSPS KKK, NSPS OOOO, or NSPS OOOOa. Once sources are subject to and in compliance with a state or Federal plan implementing EG OOOOc, and if that plan is just as stringent as or more stringent than the presumptive standards in EG OOOOc, the source will be deemed to comply with the previous respective VOC NSPS, and no longer subject to the methane NSPS, and will comply with only the state or Federal plan implementing EG OOOOc. Because the EG OOOOc does not contain SO₂ standards, sources subject to SO₂ standards in NSPS OOOO or NSPS OOOOa would continue to comply with their respective SO₂ standards unless they modify and become subject to the requirements in NSPS OOOOb.

In this rulemaking, the EPA is finalizing standards for dry seal centrifugal compressor and intermittent vent process controllers for the first time in NSPS OOOOb and presumptive standards in EG OOOOc. These designated facilities ( i.e., dry seal centrifugal compressors and intermittent vent process controllers) are not subject to regulation under a previous NSPS. The EPA is also finalizing presumptive standards in EG OOOOc for fugitive emissions at compressor stations, pumps at natural gas processing plants, and process controllers at natural gas processing plants that are all the same or more stringent than previous standards in NSPS KKK, NSPS OOOO, and NSPS OOOOa, as applicable. Additionally, the final presumptive standards in EG OOOOc for pumps (excluding processing) and natural gas processing plant equipment leaks are more stringent than the standards in NSPS OOOOa for pneumatic pumps and the standards in NSPS KKK, NSPS OOOO, and NSPS OOOOa for natural gas processing plant equipment leaks.

For wet seal centrifugal compressors, two different standards are in place in the previous NSPS. NSPS KKK is an equipment standard that provides several compliance options including: (1) Operating the compressor with the barrier fluid at a pressure that is greater than the compressor stuffing box pressure; (2) equipping the compressor with a barrier fluid system degassing reservoir that is routed to a process or fuel gas system, or that is connected by a CVS to a control device that reduces VOC emissions by 95 percent or more; or (3) equipping the compressor with a system that purges the barrier fluid into a process stream with zero VOC emissions to the atmosphere. NSPS KKK exempts a compressor from these requirements if it is either equipped with a closed vent system to capture and transport leakage from the compressor drive shaft back to a process or fuel gas system or to a control device that reduces VOC emissions by 95 percent, or if it is designated for no detectable emissions (NDE). NSPS OOOO and NSPS OOOOa require 95 percent reduction of emissions from each centrifugal compressor wet seal fluid degassing system. NSPS OOOO and OOOOa also allow the alternative of routing the emissions to a process. For sources transitioning from NSPS KKK to EG OOOOc, the EPA is finalizing a subcategory for wet seal centrifugal compressors at onshore natural gas processing plants for which construction, reconstruction, or modification commenced after January 20, 1984, and on or before August 23, 2011. This subcategory will apply to all sources that were previously subject to NSPS KKK, and have EG OOOOc presumptive standards that are equivalent to NSPS KKK with three compliance options including: (1) operating the compressor with the barrier fluid at a pressure that is greater than the compressor stuffing box pressure; (2) equipping the compressor with a barrier fluid system degassing reservoir that is routed to a process or fuel gas system, or that is connected by a CVS to a control device that reduces methane emissions by 95 percent or more; or (3) equipping the compressor with a system that purges the barrier fluid into a process stream with zero methane emissions to the atmosphere. While EG OOOOc specifically addresses methane and not VOC, any reductions from the methane standards contained in this subcategory that reduce methane as established in a state or Federal plan implementing EG OOOOc will similarly reduce VOCs. Therefore, wet seal centrifugal compressors within this subcategory will only need to comply with a state or Federal plan implementing EG OOOOc and will then no longer need to comply with NSPS KKK. The EPA is not aware of any wet seal centrifugal compressors subject to NSPS OOOO or NSPS OOOOa, and the EPA believes that centrifugal compressors installed since those rules went into effect (August 2011 and September 2015) are utilizing dry seals rather than wet seals.

Similarly, there are two different standards for reciprocating compressors in the previous NSPS: (1) NSPS KKK requires the use of a seal system and includes a barrier fluid system that prevents leakage of VOC to the atmosphere for reciprocating compressors located at natural gas processing plants, and (2) NSPS OOOO and NSPS OOOOa require changing out the rod packing every 3 years or routing emissions to a control. For sources transitioning from NSPS KKK to EG OOOOc, the EPA is finalizing a subcategory for reciprocating compressors at onshore natural gas processing plants for which construction, reconstruction, or modification commenced after January 20, 1984, and on or before August 23, 2011. This subcategory will apply to all sources that were previously subject to the VOC standards of NSPS KKK and have EG OOOOc presumptive standards that are equivalent to the VOC standards of NSPS KKK with the requirement of the use of a seal system and including a barrier fluid system that prevents leakage of methane to the atmosphere. Again, while EG OOOOc specifically regulates methane and not VOC, any methane standards contained in this subcategory that reduce methane as established in a state or Federal plan implementing EG OOOOc will similarly reduce VOCs. Therefore, reciprocating compressors within this subcategory will only need to comply with a state or Federal plan implementing EG OOOOc and will then no longer need to comply with NSPS KKK. For sources transitioning from NSPS OOOO and NSPS OOOOa, as previously explained in section XII.E.1.d of the November 2021 Proposal and section IV.I of the December 2022 Supplemental Proposal, the EPA concludes that the final EG OOOOc presumptive methane standard is more efficient at discovering and reducing any emissions that may develop than the set 3-year replacement interval from NSPS OOOO and NSPS OOOOa. Overall, the final presumptive standards in EG OOOOc would result in more rod packing replacements, thereby reducing more emissions compared to the 3-year interval. Therefore, reciprocating compressors transitioning from NSPS OOOO and NSPS OOOOa only need to comply with a state or Federal plan implementing EG OOOOc, and will then be no longer needed to comply with NSPS OOOO or NSPS OOOOa.

The affected facility for storage vessels is defined in the NSPS OOOO and NSPS OOOOa as a single storage vessel with the potential to emit (PTE) greater than 6 tons of VOC per year and the standard that applies is 95 percent emissions reduction. Under the final EG OOOOc, the designated facility is a tank battery with the PTE greater than 20 tons of methane per year with the same 95 percent emission reduction standard. Affected facilities under NSPS OOOO or OOOOa that are part of a designated facility under the EG presumptive standard would be required to meet the 95 percent reduction standard, and therefore only need to comply with a state or Federal plan implementing EG OOOOc and will then no longer need to comply with NSPS OOOO or OOOOa. Affected facilities under NSPS OOOO or OOOOa that emit 6 tpy or more of VOCs but that do not meet the PTE 20 tons of methane per year definition would continue to comply with the 95-percent emissions reduction standard in their respective NSPS. Scenarios regarding further physical or operational changes in NSPS OOOOb that would reclassify sources from the previous NSPS and/or EG OOOOc into NSPS OOOOb are discussed in section IV.J.1.b of this preamble.

Similarly, process controller affected facilities not located at natural gas processing plants are defined as single high-bleed controllers with a low-bleed standard under NSPS OOOO and NSPS OOOOa, while the designated facility under EG OOOOc is defined as a collection of natural gas-driven process controllers at a site with a zero-emissions standard (discussed further in section IV.D of this preamble). Because the final zero-emissions presumptive standard in EG OOOOc is more stringent than the low-bleed standard found in the previous NSPS, sources only need to comply with a state or Federal plan implementing EG OOOOc and will then no longer need to comply with NSPS OOOO and OOOOa (assuming the state or Federal plan implementing EG OOOOc is as stringent as the presumptive standard of zero emissions in the final EG).

Lastly, standards for fugitive emissions from well sites under NSPS OOOOa require semiannual OGI monitoring on all components at the well site except for wellhead only well sites (which are not affected facilities), while the presumptive standards under the final EG OOOOc would require quarterly OGI monitoring with bimonthly audible, visual, and olfactory (AVO) inspections at well sites with major production and processing equipment, semiannual OGI combined with quarterly AVO inspections at multi-wellhead only well sites, and quarterly AVO inspections for small sites and single wellhead well sites, as described in sections X and XI of this preamble. It is clear that the final presumptive standards in EG OOOOc for well sites with major production and processing equipment and the final presumptive standards for multi-wellheads only well sites are both more stringent than the semiannual OGI monitoring standard under NSPS OOOOa because one would require more frequent OGI monitoring while the other would require AVO inspections in addition to semiannual OGI monitoring. Therefore, these existing well sites only need to comply with a state or Federal plan implementing EG OOOOc and will then no longer need to comply with NSPS OOOOa. Likewise, as the EPA has concluded that the advanced methane detection technology periodic screening work practice being finalized in EG OOOOc is equivalent to the standard fugitive emissions work practice using OGI and AVO, the advanced methane detection technology periodic screening work practice being finalized in EG OOOOc is also more stringent than the OGI monitoring standard in NSPS OOOOa. In order to allow owners and operators to adopt implementation of these advanced methane detection technologies early, the EPA is finalizing in NSPS OOOOa an option for owners and operators to comply with the advanced methane detection technology work practices in NSPS OOOOb in lieu of the OGI surveys required in 40 CFR 60.5397a. The EPA recognizes that there are some differences between the definition of fugitive emissions component between EG OOOOc and NSPS OOOOa. In NSPS OOOOa, the EPA has clarified that if an owner or operator subject to NSPS OOOOa chooses to implement the advanced methane detection technology work practices in NSPS OOOOb the definitions in 40 CFR 60.5430b, which would include the definition of fugitive emissions component, apply for the purposes of the advanced methane detection technology work practice.

For existing single wellhead only well sites and small sites that are previously subject to the semiannual monitoring under NSPS OOOOa and transitioning to EG OOOOc, the EPA is concluding that, as explained in more detail in section IV.A of this preamble, AVO is effective, and therefore OGI is unnecessary, for detecting fugitive emissions from many of the fugitive emissions components at these sites. By requiring more frequent visits to the sites, the final presumptive standard in EG OOOOc would allow earlier detection and repair of fugitive emissions, in particular large emissions from components such as thief hatches on uncontrolled storage vessels. The EPA concludes that the final presumptive standards under the proposed EG OOOOc would effectively address the fugitive emissions at these well sites and that semiannual OGI monitoring would no longer be necessary for these well sites. Therefore, these sources need to comply with NSPS OOOOa until they are in compliance with a state or Federal plan implementing EG OOOOc. Once subject to and in compliance with such a plan, then they no longer need to comply with NSPS OOOOa.

X. Summary of Final Standards NSPS OOOOb and EG OOOOc

A. Fugitive Emissions From Well Sites, Centralized Production Facilities, and Compressor Stations

As described in section IV.A of the December 2022 Supplemental Proposal preamble (87 FR 74722, December 6, 2022) and section XI.A of the November 2021 Proposal preamble (86 FR 63169, November 15, 2021), fugitive emissions are unintended emissions that can occur from a range of components at any time due to leaks. Collectively, these emissions constitute one of the largest sources of methane from this source category, representing approximately 700 kt of the 2019 methane emissions from this source category reported in the GHGI. The magnitude of these emissions can also vary widely across different facilities and over time. The EPA has historically addressed fugitive emissions from the Crude Oil and Natural Gas source category through ground-based component level monitoring using OGI or EPA Method 21 of appendix A–7 to 40 CFR part 60.

This section of the preamble presents a summary of the final standards for NSPS OOOOb and final presumptive standards for EG OOOOc regarding fugitive emissions components affected facilities and designated facilities located at well sites, centralized production facilities, and compressor stations. As defined in the final NSPS OOOOb, a fugitive emissions component is “any component that has the potential to emit fugitive emissions of methane or VOC at a well site, centralized production facility, or compressor station, such as valves (including separator dump valves), connectors, pressure relief devices, open-ended lines, flanges, covers and closed vent systems not subject to § 60.5411b, thief hatches or other openings on a storage vessel not subject to § 60.5395b, compressors, instruments, meters, and yard piping.”

1. Fugitive Emissions at Well Sites and Centralized Production Facilities

a. NSPS OOOOb

i. Affected Facility

The standards apply to each fugitive emissions components affected facility, which is the collection of fugitive emissions components at a well site or centralized production facility.

ii. Final Standards

In this final rule, the EPA is finalizing the work practice standards for monitoring and repairing (including replacing) fugitive emissions components at fugitive emissions components affected facilities located at well sites and centralized production facilities, as proposed in the December 2022 Supplemental Proposal. Specifically, the EPA is finalizing monitoring and repair programs for four subcategories of well sites as follows:

1. Single wellhead only well sites: Quarterly AVO inspections,

2. Multi-wellhead only well sites: Semiannual OGI (or EPA Method 21) monitoring following the monitoring plan required in 40 CFR 60.5397b and quarterly AVO inspections,

3. Well sites with major production and processing equipment and centralized production facilities: Quarterly OGI (or EPA Method 21) monitoring following the monitoring plan required in 40 CFR 60.5397b and bimonthly AVO inspections, and

4. Small well sites: Quarterly AVO inspections.

The third subcategory includes well sites and centralized production facilities that have:

1. One or more controlled storage vessels or tank batteries,

2. One or more control devices,

3. One or more natural gas-driven process controllers or pumps, or

4. Two or more pieces of major production or processing equipment not listed in items 1–3.

The EPA explained in the December 2022 Supplemental Proposal that it was proposing to define this third subcategory as such (in particular items 1–3 above) “because those sources individually are known sources of super-emitter emissions events (see section IV.C) and are subject to quarterly OGI for compliance assurance (storage vessels and pneumatic controllers) or are subject to other continuous monitoring requirements (control devices).” As discussed in section XI.D.3 of this preamble, we have changed the terminology from “pneumatic controllers” to “process controllers” in the final rule.

Also, as explained in the December 2022 Supplemental Proposal, the fourth subcategory, small well sites, includes single wellhead well sites that do not contain any controlled storage vessels, control devices, natural gas-driven process controllers, or natural gas-driven pumps and contain only one piece of certain major production and processing equipment. Major production and processing equipment that would be allowed at a small well site would include a single separator, glycol dehydrator, centrifugal or reciprocating compressor, heater/treater, or a storage vessel that is not controlled. Id. at 74723.

For the second subcategory, multi-wellhead only well sites, where semiannual OGI monitoring is required, subsequent semiannual monitoring would be required to occur at least 4 months apart and no more than 7 months apart. For the third subcategory, well sites with major production and processing equipment and centralized production facilities, where quarterly OGI monitoring is required, subsequent quarterly monitoring would occur at least 60 days apart. Quarterly OGI monitoring may be waived when temperatures are below 0 °F for two of three consecutive calendar months of a quarterly monitoring period.

In the final rule, the EPA clarified that the monitoring requirements for fugitive emissions components do not apply to buried yard piping and associated buried fugitive emissions components ( e.g., buried connectors on the buried yard piping).

In addition to clarifying in the fugitive emissions component definition that “valves” include dump valves, the EPA specifies in the final rule the requirement to visually inspect the separator dump valve while at the site conducting regular AVO monitoring surveys (either quarterly or bimonthly, depending on the site) to ensure that it is operating as designed and not stuck in an open position. As proposed in the December 2022 Supplemental Proposal, the EPA is also finalizing the closed and sealed requirement for thief hatches or other openings (on storage vessels or tank batteries) that are fugitive emissions components and the requirement to visually inspect the hatch to confirm compliance during the AVO monitoring survey.

The EPA is finalizing the following repair timelines. A first attempt at repair of malfunctioning separator dump valves, open or unsealed thief hatches and other storage vessel openings, or other sources of fugitive emissions identified with AVO must be made within 15 days after the detection, with final repair required within 15 days after the first attempt. A first attempt at repair of the source of fugitive emissions identified with OGI or EPA Method 21 must be made within 30 days after the detection, with final repair required within 30 days after the first attempt. The EPA is also finalizing provisions to allow a delay of repair if the repair is technically infeasible, would require a vent blowdown, well shutdown, or well shut-in, would be unsafe to repair during operation of the unit, or would require replacement parts that are unavailable for certain reasons (see section XI.A.1.e for details); in no case is delay allowed beyond 2 years.

Monitoring surveys of fugitive emissions components affected facilities at a well site or centralized production facility must continue until the site or facility is permanently closed following the required well closure plan. After all well closure activities are completed, a final OGI survey of the site must be conducted (and recorded in the well closure plan) and any emissions detected must be eliminated.

iii. Recordkeeping and Reporting Requirements

The final rule requires specific recordkeeping and reporting requirements for each fugitive emissions components affected facility located at a well site or centralized production facility. The recordkeeping requirements closely follow those in the December 2022 Supplemental Proposal but incorporate the addition of new delay of repair recordkeeping requirements. In the case of delay of repair due to parts unavailability, operators must document the date the leak was added to the delay of repair list, the date the replacement fugitive emissions component or part thereof was ordered, the anticipated delivery date, and the actual delivery date.

The reporting requirements are unchanged from the December 2022 Supplemental Proposal. Sources would be required to report the designation of the type of site ( i.e., well site or centralized production facility) at which the fugitive emissions components affected facility is located. In addition, for each fugitive emissions components affected facility that becomes an affected facility during the reporting period, the date of the startup of production or the date of the first day of production after the modification would be required to be reported for well sites or centralized production facility. Each fugitive emissions components affected facility at a well site would also be required to specify in the annual report what type of site it is ( i.e., a single wellhead only well site, small well site, a multi-wellhead only well site, or a well site with major production and processing equipment) and to report information on changes such as the removal of all major production and processing equipment or well closure activities during the reporting period.

For fugitive emissions components affected facilities located at well sites and centralized production facilities, the following information is required to be included in the annual report for fugitive emissions monitoring surveys conducted using AVO, OGI, or Method 21:

• Date of the survey,
• Monitoring instrument or, if the survey was conducted using AVO, notation that AVO was used,
• Any deviations from key monitoring plan elements or a statement that there were no deviations from these elements of the monitoring plan,
• Number and type of components for which fugitive emissions were detected,
• Number and type of fugitive emissions components that were not repaired as required,
• Number and type of fugitive emissions components (including designation as difficult-to-monitor or unsafe-to-monitor, if applicable) on delay of repair and explanation for each delay of repair, and
• Date of planned shutdown(s) that occurred during the reporting period if there are any components that have been placed on delay of repair.

For fugitive emissions components affected facilities located at well sites and centralized production facilities complying with an alternative fugitive emissions standard under 40 CFR 60.5399b, the annual report must identify the alternative standard and include either the site-specific report or the same information described above. For fugitive emissions components affected facilities located at well sites and centralized production facilities complying with an alternative fugitive emissions standard under 40 CFR 60.5398b, the annual report must include information specified in 40 CFR 60.5424b.

b. EG OOOOc

i. Designated Facility

These final EG define designated facilities as the collection of fugitive emissions components at a well site or a centralized production facility.

ii. Final Presumptive Standards

The presumptive methane standards for existing sources under EG OOOOc are the same as the methane standards for new sources under NSPS OOOOb.

2. Fugitive Emissions at Compressor Stations

a. NSPS OOOOb

i. Affected Facility

The standards apply to each fugitive emissions components affected facility, which is the collection of fugitive emissions components at a compressor station.

ii. Final Standards

In this final rule, the EPA is finalizing the quarterly OGI (or EPA Method 21) monitoring requirement for fugitive emissions components affected facilities located at compressor stations, as proposed in the December 2022 Supplemental Proposal. Specifically, the EPA is finalizing the requirement that quarterly surveys be performed using OGI or EPA Method 21 following the monitoring plan required in the final regulatory text at 40 CFR 60.5397b. The EPA is also finalizing the requirement to conduct monthly AVO monitoring at compressor stations. Any indications of fugitive emissions identified via AVO would be subject to repair requirements.

The EPA is also finalizing the repair timelines proposed in the December 2022 Supplemental Proposal. A first attempt at repair of the source of fugitive emissions identified with AVO must be made within 15 days after the detection, with final repair required within 15 days after the first attempt. A first attempt at repair of the source of fugitive emissions identified with OGI or EPA Method 21 must be made within 30 days after the detection, with final repair required within 30 days after the first attempt. The EPA is also finalizing provisions to allow a delay of repair if the repair is technically infeasible, would require a vent blowdown, a compressor station shutdown, a well shutdown or well shut-in, would be unsafe to repair during operation of the unit, or would require replacement parts that are unavailable for certain reasons (see section XI.A.2.b for details); in no case is delay allowed beyond 2 years.

The final rule for fugitive emissions components affected facilities located at compressor stations includes the requirement that consecutive quarterly monitoring surveys be conducted at least 60 days apart. As proposed, the EPA is finalizing the provision that the quarterly OGI monitoring may be waived when temperatures are below 0 °F for 2 of 3 consecutive calendar months of a quarterly monitoring period.

iii. Recordkeeping and Reporting Requirements

The final rule requires specific recordkeeping and reporting requirements for each fugitive emissions components affected facility. The recordkeeping requirements closely follow those in the December 2022 Supplemental Proposal but incorporate the addition of new delay of repair recordkeeping requirements. In the case of delay of repair due to parts unavailability, operators must document the date the leak was added to the delay of repair list, the date the replacement fugitive emissions component or part thereof was ordered, the anticipated delivery date, and the actual delivery date.

The reporting requirements are unchanged from the December 2022 Supplemental Proposal. Sources would be required to report the designation of the type of site ( i.e., compressor station) at which the fugitive emissions components affected facility is located. For fugitive emissions components affected facilities located at compressor stations, the following information is required to be included in the annual report for monthly surveys conducted using AVO, OGI, or Method 21:

• Date of the survey,
• Monitoring instrument or, if the survey was conducted using AVO, notation that AVO was used,
• Any deviations from key monitoring plan elements or a statement that there were no deviations from these elements of the monitoring plan,
• Number and type of components for which fugitive emissions were detected,
• Number and type of fugitive emissions components that were not repaired as required,
• Number and type of fugitive emissions components (including designation as difficult-to-monitor or unsafe-to-monitor, if applicable) on delay of repair and explanation for each delay of repair, and
• Date of planned shutdown(s) that occurred during the reporting period if there are any components that have been placed on delay of repair.

For fugitive emissions components affected facilities located at compressor stations complying with an alternative fugitive emissions standard under 40 CFR 60.5399b, the annual report must identify the alternative standard and include either the site-specific report or the same information described above. For fugitive emissions components affected facilities located at compressor stations complying with an alternative fugitive emissions standard under 40 CFR 60.5398b, the annual report must include information specified in 40 CFR 60.5424b.

b. EG OOOOc

i. Designated Facility

These final EG define designated facilities as the collection of fugitive emissions components at a compressor station.

ii. Final Presumptive Standards

The presumptive methane standards for existing sources under EG OOOOc are the same as the methane standards for new sources under NSPS OOOOb.

B. Advanced Methane Detection Technology Work Practices

The EPA has included the use of advanced methane detection technologies in this final rule, in recognition of the rapid and continued advancement of these technologies and their current use by owner or operators to supplement their existing ground based OGI surveys and AVO inspections. Industry has applied many such technologies, from on-site sensor networks to aerial flyovers using remote sensing technology that can screen hundreds of sites in a single deployment, to efficiently detect methane emissions at a variety of facilities and focus their methane mitigation efforts. In the November 2021 Proposal, we proposed to allow owners and operators to undertake an approach with bimonthly periodic screening events using these technologies as an alternative to periodic OGI surveys. In doing so, the EPA acknowledged that these advanced methane detection technologies have important advantages, including the ability to detect fugitive emissions quickly and cost-effectively in a manner that may be less susceptible to operator error or judgement than traditional leak detection technologies. Because many of these advanced methane detection technologies are designed to scan multiple sites at once, owners and operators have used them as an effective “screening” tool to rapidly identify particular high-emitting sites that warrant targeted inspection and repair efforts.

The inclusion of these advanced methane detection technologies in NSPS OOOOb and EG OOOOc received widespread support from stakeholders. We also received feedback on how the EPA could improve on its proposal and expand this approach to maximize its efficacy in reducing methane emissions and its utility as a compliance flexibility for owners and operators. In the December 2022 Supplemental Proposal, we provided additional flexibility for advanced methane technologies using the periodic screening approach by allowing the frequency of the surveys to vary according to the sensitivity of the technology used, instead of requiring the same frequency of monitoring for all technologies ( i.e., periodic screening surveys performed with technologies with lower detection thresholds would need to be performed less frequently than screening surveys performed with technologies with higher detection thresholds). We also introduced a separate alternative work practice using continuous methane monitoring systems. Finally, we proposed a streamlined approach to approving new technology that is similar to our current alternative test method approval process. This approach ensures that the advanced methane detection technologies used to conduct periodic screening or continuous monitoring will provide consistent and reliable information for emission reductions, while also allowing an easier pathway for owners and operators to adopt the use of the technologies. We believe that this approach will continue to incentivize the continued development and improvement of these technologies, thus leading to even greater emission reductions.

This section summarizes the final provisions in NSPS OOOOb and in the model rule implementing EG OOOOc for the use of advanced methane detection technologies in lieu of OGI and/or AVO at well sites, centralized production facilities, and compressor stations. As described here, the EPA is finalizing a compliance option that would allow the use of these advanced methane detection technologies as an alternative to the use of ground-based OGI surveys, EPA Method 21 (which the final rule continues to allow as an alternative to OGI), and AVO inspections to identify emissions from the collection of fugitive emissions components located at well sites, centralized production facilities, and compressor stations. In response to comments received on the December 2022 Supplemental Proposal, the EPA has made revisions and clarifications to the periodic screening approach, continuous monitoring provisions, and alternative test method process for approving advanced methane detection technologies for use in these work practices.

1. Periodic Screening

In this final rulemaking, the EPA is expanding the proposed alternative periodic screening approach to provide more flexibility in selection of appropriate advanced methane detection technology and to account for the spatial resolution of these technologies. The EPA has also re-evaluated the equivalency modeling from the December 2022 Supplemental Proposal used to develop the screening frequency matrix and is finalizing revisions to these tables to account for uncertainty in the models as discussed in the revised Supplemental TSD Fugitive Emissions Abatement Simulation Toolkit (FEAST) Memo. The updated periodic screening frequency matrices are specified in tables 3 and 4 of the final NSPS OOOOb and the model rule implementing the final EG OOOOc. The EPA is also finalizing an interim periodic screening option that will expire on March 9, 2026. See section XI.B.1 of this preamble for more information on this interim periodic screening matrix.

For periodic screening using advanced methane detection technology, the final rules provide greater flexibility by allowing the owner or operator to utilize multiple detection technologies in combination, instead of requiring the owner or operator to choose one technology. This approach will allow end-users to optimize their periodic screening program by choosing the most suitable technology based on time of year and availability of technology providers. The periodic screening frequency will be based on the technology with the highest aggregate detection threshold that the owner or operator lists as a technology they plan to use in their monitoring plan ( e.g., if you use methods with aggregate detection thresholds of 15 kg/hr, your periodic screenings must be conducted monthly). The final rule also allows an owner or operator to replace any periodic screening survey with an OGI survey.

This final rulemaking will require owners and operators to develop a monitoring plan, which can be site-specific or cover multiple sites. The monitoring plan must contain the following information at a minimum, consistent with the December 2022 Supplemental Proposal:

• Identification of each site, including latitude and longitude;

• Identification of the alternative test methods(s) used ( i.e., advanced methane detection technology) and required frequency;

• Contact information of the entities performing the screening;
• Procedures for conducting OGI surveys;
• Procedures for identifying and repairing fugitive emissions components, covers, and closed vents systems when emissions are detected; and
• Procedures for verifying repairs of fugitive emissions components, covers, and closed vents system.

The final rulemaking finalizes the proposed timeframe in the December 2022 Supplemental Proposal that an owner or operator must initiate periodic screenings using advanced methane detection technology, within 90 days after startup or modification of a fugitive emissions components affected facility and storage vessel affected facility at new, modified, or existing well sites, centralized production facilities, and/or compressor stations, as well as timeframes for initiating periodic screenings if an owner or operator opts to switch to periodic screenings at a later time ( i.e., the owner or operator was originally conducting fugitive emissions surveys with OGI or EPA Method 21). The final rule also sets timeframes for conducting annual OGI surveys, if an owner or operator is required to do so based on the periodic screening matrix.

The final rulemaking finalizes the requirement in the December 2022 Supplemental Proposal that owners and operators must receive the data from a periodic screening event within 5 calendar days. If the screening event indicates a confirmed detection, the owner or operator must conduct follow-up monitoring. In the final rule, we are allowing a more targeted follow-up survey, dependent on the spatial resolution of the advanced methane detection technology used during the periodic screening event. The final rulemaking includes three different classifications for spatial resolution: facility-level, which must be able to identify emissions within the boundary of a well site, centralized production facility, or compressor station; area-level, which must be able to identify emissions within a radius of 2 meters of the emission source; and component-level, which must be able to identify emissions within a radius of 0.5 meters of the emission source. The follow-up monitoring that must be conducted for a confirmed detection during a periodic screening event using a technology with facility-level spatial resolution includes:

• A monitoring survey of all the fugitive emissions components in an affected facility using either OGI or EPA Method 21;
• Inspection of all covers and closed vent systems of the affected facility with either OGI or EPA Method 21; and
• Visual inspection of all closed vent systems and covers to identify if there are any defects.

The follow-up monitoring that must be conducted for a confirmed detection during a periodic screening event using a technology with area-level spatial resolution includes:

• A monitoring survey of all the fugitive emissions components located within a 4-meter radius of the location of the confirmed detection using either OGI or EPA Method 21; and

• If the confirmed detection occurred in a portion of a site with a storage vessel or closed vent system, inspection of all covers and closed vent systems that are connected to all storage vessels and closed vent systems that are within a 2-meter radius of the confirmed detection location ( i.e., you must inspect the whole system that is connected to the portion of the system, not just the portion of the system that falls within the radius of the detected event). Inspection must be conducted using either OGI or EPA Method 21, as well as visually to identify defects.

The follow-up monitoring that must be conducted for a confirmed detection during a periodic screening event using a technology with component-level spatial resolution includes:

• A monitoring survey of all the fugitive emissions components located within a 1-meter radius of the location of the confirmed detection using either OGI or EPA Method 21; and

• If the confirmed detection occurred in a portion of a site with a storage vessel or closed vent system, inspection of all covers and closed vent systems that are connected to all storage vessels and closed vent systems that are within a 0.5-meter radius of the confirmed detection location ( i.e., you must inspect the whole system that is connected to the portion of the system, not just the portion of the system that falls within the radius of the detected event). Inspection must be conducted, as well as visually to identify defects.

As proposed, the final rulemaking requires that the owner or operator follow the repair requirements and timelines in the December 2022 Supplemental Proposal for fugitive emissions components where emissions are detected from fugitive components, and the repair requirements for covers and closed vent systems (CVS) if emissions are detected during the follow-up monitoring survey. We are also finalizing as proposed the requirement to conduct an investigative analysis when the source of a confirmed detection is determined to be a control device subject to the rule or an emission from or defect from a cover or closed vent system associated with an affected facility, although we have refined the requirements. These requirements include:

• Repair all fugitive emissions components, covers, and closed vent systems within 30 days after receiving the periodic screening data (except where delay of repair is allowed).
• Initiate an investigative analysis within 5 days if an emission or defect in a closed vent system or cover is determined to be the cause of the emissions.
• Initiate an investigative analysis within 24 hours of receiving the monitoring survey and inspection results if a failed control device is determined to be the cause of the emissions.
• Investigative analyses must be used to determine the underlying primary cause and other contributing causes to the emissions event. Owners and operators must determine the actions needed to bring the control device into compliance; how to prevent future failures of the control device from the same underlying cause(s); and updates are necessary to the engineering analysis for the cover or closed vent system to prevent future emissions from the cover and closed vent system.

2. Continuous Monitoring Screening

In this final rulemaking, the EPA is finalizing the continuing monitoring approach and associated work practice in the December 2022 Supplemental Proposed Rule with some changes to better account for background methane concentrations and to better incorporate additional types of measurement systems. The EPA has reexamined the proposed detection threshold for these systems and has adjusted that threshold in the final rule to better account for background methane concentrations.

The final rule includes defined requirements for operating continuous monitoring systems, including using advanced methane monitoring technology approved by the EPA for this purpose. This system must be set-up in a manner to generate a valid methane mass emission rate (or equivalent) once at least every twelve-hour block, have an operation downtime of less than 10 percent, and have checks in place to monitor the health of the system. We have revised the proposed sensitivity requirements to allow systems with detection thresholds of 0.40 kg/hr of methane or lower and, are requiring systems to transmit data at least once every 24 hours. The final rule maintains the timeframe in the December 2022 Supplemental Proposal for when the owner or operator must initiate continuous monitoring using advanced methane detection technology ( i.e., within 120 days after startup of a fugitive emissions components affected facility and storage vessel affected facility at new, modified, and existing well sites, centralized production facilities, and/or compressor stations), as well as timeframes for initiating continuous monitoring if an owner or operator opts to switch to periodic screenings at a later time ( i.e., the owner or operator was originally conducting fugitive emissions surveys with OGI or EPA Method 21).

In the final rulemaking, we have revised the “action-levels” in the December 2022 Supplemental Proposal to account for the potential for background methane emission levels at many of these sites. An action-level is the time weighted average that triggers an investigative analysis to identify the cause(s) of the exceedance. For affected facilities located at wellhead only well sites, these “action-levels” are as follows:

• Rolling 90-day average of 1.2 kg/hr of methane over the site-specific baseline.
• Rolling 7-day average of 15 kg/hr of methane over site-specific baseline.

For affected facilities located at well sites with major production and processing equipment, small well sites, centralized production facilities, and compressor stations, the action levels are as follows:

• Rolling 90-day average of 1.6 kg/hr of methane over the site-specific baseline.
• Rolling 7-day average of 21 kg/hr of methane over the site-specific baseline.

The final rule includes a new and defined set of criteria for the timeframe and site conditions under which to establish the site-specific baseline emissions since the December 2022 Supplemental Proposal, finalizes as proposed how to calculate emissions after the baseline has been established, and has refined the proposed actions the owner or operator must take when an “action-level” is exceeded. Prior to establishing the site-specific baseline, the owner or operator must perform inspections of the fugitive emissions components, any covers and closed vent systems, and control devices to ensure the site is leak free and in compliance with the requirements in NSPS OOOOb and/or the applicable state plan implementing EG OOOOc. The owner or operator must then record the site-level emissions from the continuous monitoring system for 30 days and determine the mean emission rate, less any time periods when maintenance activities were conducted.

The final rule has changed the requirements in the December 2022 Supplemental Proposal for how to calculate the 7-day and 90-day rolling average to account for the site-specific baseline and has maintained the intent of required follow-up activities when exceedances of the action-level have occurred. We have also changed the nomenclature of the follow-up activities from “root cause analysis” to “investigative analysis” and from “corrective action” to “mass emission rate reduction plan” to eliminate confusion caused by the terminology we used in the December 2022 Supplemental Proposal. We have also more clearly specified the requirements for these activities. The requirements for an investigative analysis are as follows:

• The investigative analysis must be initiated within 5 days after an exceedance of an action-level to determine the underlying primary and contributing cause(s).
• When the 7-day action-level is exceeded, within 5 days after the exceedance the investigative analysis must be completed and initial steps must be taken to reduce the mass emission rate.
• When the 90-day action-level is exceeded, within 30 days after the exceedance the investigative analysis must be completed and initial steps must be taken to reduce the mass emission rate.

An owner or operator must develop a mass emission rate reduction plan when any of the following conditions have been met:

• For an exceedance of the 90-day action-level, 30-day average mass emission rate for the 30 days following the completion of the investigative analysis and initial steps to reduce the mass emission rate is not below the applicable 90-day action-level.
• For an exceedance of the 7-day action-level, the mass emission rate for the 24-hour period after the completion of the investigative analysis and initial steps to reduce the mass emission rate is not below the applicable 7-day action-level.

• The actions needed to reduce the emission rate below the applicable action-level will take more than 30 days to implement.

3. Alternative Test Method for Methane Detection Technology

In this final rule, the EPA has strengthened the alternative test method approval process for advanced methane detection technology used in periodic screening and continuous monitoring. The EPA has further clarified the Administrator authority in the approval process, the criteria for who may submit requests for approval, and the requirements for what information must be submitted by those entities seeking approval.

This final rule specifies a process for applying and obtaining the EPA's approval for the use of an advanced methane detection technology in lieu of the required monitoring methods in the rule by submitting the test method for the alternative technology. However, instead of relying on existing provisions for alternative test methods 40 CFR 60.8(b), we are in the final rule citing a new alternative test method provision in 40 CFR 60.5398b(d). This provision incorporates specific criteria for the review, evaluation, and potential use of advanced methane detection technology for use in periodic screening, continuous monitoring, and/or super-emitter detection.

This final rule maintains the procedures in the December 2022 Supplemental Proposal for submitting an alternative test method for methane detection technology request. These requests must be submitted to the Leader, Measurement Technology Group along with any supporting data to the methane detection portal at ( www.epa.gov/emc/oil-and-gas-alternative-test-methods ). Confidential Business Information (CBI) must not be submitted through this portal; detailed instructions for submitting information for which an entity submits a claim of CBI are provided in 40 CFR 60.5398b(d)(1). The Administrator will complete an initial completeness review of submissions within 90 days. An approval or disapproval will be issued in writing within 270 days after receiving a request. Submission approvals may be considered on a site-specific basis or more broadly applicable, depending on the technology and the information provided in the request.

The December 2022 Supplemental Proposal included limitations on which entities could submit an alternative test method request. The final rule retains these provisions while also providing improvements to allow for proprietary advanced methane measurement technology internally developed by owners and operators. Any entity that meets the following specifications may submit an alternative test method request:

• The entity must be an individual or organization located in or that has representation in the United States.
• The entity must be an owner or operator of an affected facility under NSPS OOOOb or EG OOOOc.
• If the entity is the not the owner or operator of an affected facility, the entity must directly represent the provider of the candidate measurement system using advanced methane detection technology and the measurement system must have been applied to measurements and monitoring in the oil and gas sector (domestically or internationally).
• The candidate measurement system must have been sold, leased, or licensed, or offered for sale, lease, or license to the general public or developed by an owner or operator for internal use and/or use by external partners.

The final rule also expands upon the information you are required to provide to the Administrator when submitting a request to use an alternative test method for advanced methane detection technology. These expanded requirements represent the minimum amount of material required by the EPA to completely understand the functionality of candidate measurement technology systems, how these systems are applied to generate a methane mass emission rate (kg/hr) or equivalent emission rate, data management, detection threshold, and spatial resolution.

The final rule requires an entity to provide the Administrator contact information for the requester, the desired applicability of the technology, and a description of the candidate measurement technology system, including:

• A description of the scientific theory and appropriate references outlining the underlying technology;
• A description of the physical instrument;

• Type of measurement and desired application ( e.g., airborne, in-situ); and

• Potential limitations of the candidate measurement system, including application limitations.

The request must also include information on how the system converts results to a mass emission rate or equivalent. This information must include the following:

• Workflow and description covering all steps and processes from measurement technology signal output to final, validated mass emission rate ( i.e., kg/hr) or equivalent.

• Description of how any meteorological data are used, including how they are collected and/or sourced.
• Identification of any model(s) used, including how inputs are determined or derived.
• All calculations used, including the defined variables for any calculations.
• A-priori methods and datasets used.
• Explanation of any algorithms/machine learning procedures used in the data processing, if applicable.

The request must also include a description of how data collected and generated by the system are collected, maintained, and stored; how these data streams are processed and manipulated, including how the resultant data processing is documented; and a description of which data streams are provided to the end-user of the data and how that information is delivered or supplied.

The EPA has further refined the supporting information that must be used to verify detection thresholds and information on how the candidate measurement system must be applied to ensure the detection thresholds are maintained during monitoring events. We have also revised the detection threshold to an average aggregate detection threshold, which is defined as the average of all site-level detection thresholds from a single deployment ( e.g., a singular flight that surveys multiple well sites, centralized production facility, and/or compressor stations). The information provided in the request must include published reports produced by either the submitting entity or an outside entity evaluating the technology, standard operating procedures, alternative testing procedure(s) (preferably in the format described in Guideline Document 45), and documents provided to end-users of the data.

The final rule includes a new requirement for entities to verify the spatial resolution of the candidate measurement system. The supporting information verifying the spatial resolution must be in the form of published report ( e.g., scientific papers) produced by either the submitting entity or an outside entity evaluating the submitted measurement technology that has been independently evaluated.

C. Super Emitter Program

This section presents a summary of the final standards for the Super Emitter Program. As described in section IV.C of the December 2022 Supplemental Proposal preamble (87 FR 74722, December 6, 2022), the EPA proposed the Super Emitter Program to ensure that this rulemaking comprehensively addresses the widespread problem of abnormally large emissions events known as super-emitters. The EPA is including the Super Emitter Program in this final rulemaking, previously proposed as the Super Emitter Response Program in the December 2022 Supplemental Proposal. The EPA has developed this program in response to recent studies, which indicate that a small portion of sources contribute almost 50 percent of the methane emissions in the oil and gas sector, and on a global scale, the largest of these emissions sources may represent as much as 12 percent of global methane emissions from oil and gas production. For purposes of this rule, a super-emitter event is one that has a quantified emission rate of 100 kg/hr of methane or greater.

As described here, this program is designed to provide a transparent, reliable, and efficient mechanism by which the EPA will provide owners and operators with timely notifications of super-emitter emissions data collected by the EPA-certified third parties using the EPA-approved remote sensing technologies ( e.g., satellites). Where such an event is attributable to a source regulated under CAA section 111 (NSPS OOOO, OOOOa, or OOOOb, or a state or Federal plan implementing EG OOOOc), the responsible owner or operator will take action in response to such notifications in accordance with the applicable regulation.

The EPA anticipates that the NSPS and presumptive standards for existing sources that are included in this final rulemaking will reduce many sources of super-emitters. However, these events sometimes arise from planned maintenance, other routine operations, and are also frequently attributable to major malfunctions or improperly operating control devices. These events are unpredictable and can occur in between routine inspections and/or fugitive emissions monitoring surveys. Moreover, these events are sufficiently large to result in significant emissions of the harmful air pollutants regulated under this rule in a short span of time. By leveraging data collected by the EPA-approved third parties using the EPA-approved methods to identify such events and providing a mechanism for the EPA to promptly notify owners and operators of such events for appropriate follow-up action, the Super Emitter Program serves as both a complement and a backstop to the other requirements of this rulemaking.

As described in our response to comments, the EPA received several comments—including from owners and operators of regulated facilities—supporting the objectives of the Super Emitter Program and the importance of timely identifying and resolving super-emitter events. In this final rulemaking, the EPA has also made a number of changes to the Super Emitter Program in order to provide appropriate oversight by the EPA, address implementation concerns raised by commenters, and ensure that the program provides owners and operators with transparent, reliable, and timely information about super-emitter events.

As described in section IV.C of the December 2022 Supplemental Proposal preamble (87 FR 74746, December 6, 2022), the EPA proposed a Super Emitter Program as a backstop to address large methane super-emitters from this sector. This program is designed for the EPA to receive super-emitter emission data collected by the EPA-certified third parties using the EPA-approved remote sensing technologies ( e.g., satellites) in a timely manner. In response to comments objecting to or otherwise expressing concerns with requiring owners and operators to respond directly to third-party notifications of super-emitter events, the EPA has revised the program in the final rulemaking such that it is the EPA, and not third parties, that will notify an identified owner or operator after reviewing third-party notifications of the presence of a super-emitter event at or near its oil and gas facility ( e.g., a specific well site, centralized production facility, gas processing plant, or compressor station), requiring the owner or operator to investigate and report the results to the EPA. Also, in response to comments, the EPA emphasizes that certified third parties will only be authorized to use remote sensing technologies such as satellites or aerial surveys— i.e., this program does not authorize third parties to enter well sites or other oil and gas facilities, and it does not allow for the use of technologies such as OGI that would require close access to such facilities.

1. Statutory Authority

The Super Emitter Program finalized in this rule is based on the EPA's authority under CAA section 114(a) to require “any person who owns or operates any emission source” (except mobile sources) to provide information necessary for purposes of carrying out the CAA and its authority to regulate sources under CAA section 111. In the 2022 Supplemental Proposal, the EPA proposed two separate legal frameworks for the Super Emitter Program. 87 FR 74752. The final Super Emitter Program is based on the second legal framework. Under this framework, the EPA's authority to require sources (regardless of whether those sources are regulated under CAA section 111) to investigate potential sources of super-emitter events and report to EPA is CAA section 114. The EPA's authority to require regulated sources to repair or otherwise address the cause of the super-emitter event is CAA section 111. In particular, for sources regulated under CAA section 111, the Super Emitter Program will serve as: (1) an additional work practice standard under NSPS OOOOb (and presumptive standard under EG OOOOc) for fugitive emissions at well sites, centralized production facilities and compressor stations, and as (2) an additional compliance assurance measure for other NSPS OOOOb affected facilities, NSPS OOOO and OOOOa affected facilities, and designated facilities under EG OOOOc.

a. Authority To Require Investigation and Reporting for all Sources

The EPA's authority to require all sources, regardless of whether they are regulated under CAA section 111, to investigate potential super-emitter events and report back to the EPA stems from the EPA's broad authority under CAA section 114(a) to require, among other things, monitoring, reporting, and recordkeeping from owners and operators of stationary sources. CAA section 114(a)(1) gives the EPA broad authority to “require any person . . . to (A) establish and maintain such records; (B) make such reports; (C) install, use and maintain such monitoring equipment, and use such audit procedures, or methods; . . . and (G) provide such other information as the administrator may reasonably require . . . .” The EPA can impose such obligations on “any person who owns or operates any emission source,” whether or not the emission source is regulated under the CAA, “[f]or the purpose of assisting in the development of any implementation plan under . . . section 7411(d) of this title, any standard of performance under section 7411 of this title,” “determining whether any person is in violation of any such standard or any requirement of such plan,” or “carrying out any provision of this chapter.” CAA section 111(b) requires that the EPA review and, if appropriate, revise an NSPS at least every 8 years following its promulgation. The information on super-emitter events from both regulated and unregulated oil and gas sources can help inform the EPA on the effectiveness of its current NSPS for this sector and potential focus in its future review. Therefore, based on the authority under CAA section 114(a), the Super Emitter Program requires owners and operators to investigate and report all sources, including non-NSPS/EG sources, that they suspect may have caused or contributed to the super-emitter event specified in the EPA notice that they have received, to ensure that a regulated source is not contributing to the event, as well as to provide useful information to the EPA in carrying out its review obligation under CAA section 111(b). The information on super-emitter events can also help owners and operators prevent or minimize losing a valuable product (natural gas).

b. Authority To Require Repair for Regulated Sources: Work Practice Standards for Fugitive Emissions

Pursuant to CAA section 111, the EPA has incorporated the Super Emitter Program, in particular the requirement to repair fugitive emissions components that are sources of super-emitter events, as a part of the BSER and therefore work practice standards for fugitive emissions components affected/designated facilities under NSPS OOOOb/EG OOOOc. As the first part of the fugitive emissions BSER and work practice standards, discussed in section X.A of this document, the EPA has established periodic monitoring and repair work practice standards as the BSER for these fugitive emissions components affected/designated facilities under NSPS OOOOb and EG OOOOc. Fugitive emissions may nevertheless occur from these components between the specified periodic monitoring. Emissions from certain fugitive emissions components can be significant (as one example, a stuck-open thief hatch) and can remain undetected until the next scheduled periodic monitoring. Accordingly, as the second part of the fugitive emissions BSER and work practice standard for affected/designated facilities under NSPS OOOOb and EG OOOOc, the EPA is requiring repair of fugitive emissions components that are the cause of super-emitter events in between routine monitoring. While the EPA has determined that it is not cost effective to require more frequent periodic monitoring, where a super-emitter event ( i.e., 100 kg/hr) is caused by fugitive emissions components, repair to reduce such large emissions is clearly cost effective. To that end, the Super Emitter Program supplements the periodic monitoring and repair work practice standards in NSPS OOOOb (and presumptive standards in EG OOOOc) by requiring repair of fugitive emissions components affected/designated facilities under these subparts that the owner or operator has identified as the source of the super-emitter event through this program. The owner or operator will conduct repair in accordance with the same repair requirements as those for fugitive emissions detected during the periodic monitoring, as specified in the applicable standard ( i.e., NSPS OOOOb or a state plan implementing EG OOOOc).

c. Authority To Require Monitoring and Reporting for Regulated Sources: Compliance Assurance for Other Regulated Sources

For regulated sources that are not fugitive emissions components affected/designated facilities under NSPS OOOOb/EG OOOOc, the presence of a super-emitter event suggests that the source may not be in compliance with the applicable requirements for that source contained in the EPA's regulations. The compliance assurance aspect of the Super Emitter Program is based on the EPA's regulations for individual emissions sources in the NSPS and EG promulgated pursuant to CAA section 111. NSPS OOOO/OOOOa/OOOOb and the model rule implementing EG OOOOc all include design and/or operational requirements and monitoring, recordkeeping, and reporting requirements to assure that standards of performance are being met. However, as explained above, super emitter events are unpredictable; they can occur between routine inspections and release significant emissions in a short span of time. To address this concern, the Super Emitter Program provides additional monitoring, reporting and recordkeeping for affected/designated facilities under NSPS OOOO/OOOOa/OOOOb and EG OOOOc based on the EPA's authority under CAA section 114(a) to impose such requirements for purposes of determining whether or not standards under these subparts are being met. Where a super-emitter event originates from one of these affected/designated facilities or associated equipment regulated under NSPS OOOO, OOOOa, OOOOb, or a state or Federal plan implementing EG OOOOc, the Super Emitter Program serves as an additional source of monitoring data to inform and alert owners and operators to check and make sure that the source and associated control device and equipment are operating as required under the applicable NSPS or State or Federal plan implementing EG OOOOc. For example, a super-emitter event may be caused by an open thief hatch on a storage vessel subject to NSPS OOOOa, which is not permitted except for very limited circumstances as defined in the rule. In that event, the Super Emitter Program serves to alert an owner or operator of the need to close the thief hatch pursuant to the requirements of NSPS OOOOa, but the Super Emitter Program does not itself impose a requirement to close the thief hatch. Since there are already requirements in place to bring emissions down to or below the applicable NSPS standards (and will be in state or Federal plans implementing EG OOOOc), the Super Emitter Program does not itself independently require specific actions to address emissions from super-emitter events attributed to NSPS or EG sources; it merely puts owners and operators on notice that action may be required to bring a source back into compliance with the applicable emission standards. To clarify this point, the final rule includes amendments to NSPS OOOO and OOOOa to incorporate relevant compliance assurance provisions of the Super Emitter Program, specifically the requirement to investigate and report whether the super-emitter event was caused by a NSPS OOOO or OOOOa affected facility or associated equipment.

2. Major Elements

The following describes the major elements in the Super Emitter Program that serve to assure the reliability of the super-emitter data that the EPA receives under this program. These elements ensure that the data the EPA receives is meaningful and lead to expeditious and effective mitigation of super-emitter events by owners and operators, whether required or voluntarily.

a. Qualifications for Third-Party Notifiers

A third party can be any independent entity, meaning that the third party does not own or operate the site where a super-emitter is detected. In this final rulemaking, the EPA is maintaining the requirements for the qualification of the third-party notifiers in the December 2022 Supplemental Proposal, including the requirement that notifiers use remote sensing technologies. These technologies and their method for operation must be approved under the advanced methane detection technology program in 40 CFR 60.5398b(d). Third parties are limited to using remote sensing technologies such as satellites or aerial surveys and would not be authorized by this program to enter a site.

b. Third-Party Notifier Certification

In this final rulemaking, the EPA establishes a framework by which we will certify third-party notifiers from whom the EPA would accept data from super-emitter events under the Super Emitter Program. The final rulemaking includes provisions governing how the third-party must submit a request to be certified, requirements that a third-party must meet to be certified and/or re-certified, obligations for notifiers to maintain records of surveys performed to maintain certification, and procedures for revoking a notifiers certification.

A third-party notifier certification request must be submitted to the Leader, Measurement Technology Group, 109 T.W. Alexander Drive, P.O. Box 12055, Research Triangle Park, NC 27711. If your request contains CBI, you must transmit these data electronically using email attachments, File Transfer Protocol, or other online file sharing services. This request must include general identification for the entity submitting the request, including the mailing address, physical address, and contact information for the principal officer and certifying officials(s). This request must also include the following information:

• Description of the advanced methane detection technologies that the third party intends to use, including reference to any alternative test method approval under 40 CFR 60.5398b(d), and any agreements with the technology providers.
• Curriculum vitae of the certifying official(s) detailing training for evaluating results of the chosen advanced methane detection technology.
• The entity's standard operating procedure(s) detailing the procedures and processes used by the entity for data review, including the accuracy of emissions data and locality data provided by the technology provider, how the entity will identify the owner or operator of a site, and procedures for handling potentially erroneous data.
• Description of the system for maintaining essential records.
• A Quality Management Plan consistent with the EPA's Quality Management Plan Standard (Directive No: CIO 2015–S–01.0, January 17, 2023).

An entity that has received third-party approval must maintain the following records in order to retain its certification status:

• Records for all surveys conducted by or sponsored by the certified third-party notifier that are the basis for a third-party super-emitter identification submitted to the EPA.
• Records for any notifications provided to the EPA and any additional data collected supporting the notification not required by the EPA to be reported.
• Records or identification of databases used to identify owner or operators of sites where super-emitter events reported to the EPA occurred.

The Administrator will assess the completeness, reasonableness, and accuracy of the third party's request based on the updated certification criteria in the final rule. Once certified, the third-party notifier will receive a unique notifier ID which will be posted at www.epa.gov/emc-third-party-certifications. If there is any material change to the information included in the third party's initial certification request, e.g., a change to the technology that the third party intends to use or a change to the certifying official(s), the final rule requires the third party to submit a revised request and be recertified before implementing those changes.

As proposed, the EPA is finalizing provisions providing for the revocation of a third party's certification under certain conditions. In response to comments, the EPA has expanded in the final rule the circumstances for removing a third-party certification, which are as follows:

• Submitting super-emitter notifications after making material changes to the third party's procedures for identifying super-emitters without seeking recertification.
• If the Administrator finds that the certified third-party notifier has persistently submitted data with significant errors.

• Having engaged in illegal activity during the assessment of a super-emitter event ( e.g., trespassing).

• Upon determination by the Administrator, following petition from the owner or operator, that the owner or operator has received from the EPA more than three notices with meaningful and/or demonstrable errors of a super-emitter event at the same oil and natural gas facility ( e.g., a well site, centralized production facility, natural gas processing plant, or compressor station), that were submitted to the EPA by the same third party, and the owner or operator demonstrates that the claimed super-emitter event did not occur. The failure of the owner or operator to find the source of the super-emitter emissions event upon subsequent inspection would not be proof, by itself, of demonstrable error on the part of the third-party notifier.

c. Notification of Super-Emitter Events

In the final rules, the EPA has amended the super-emitter notification process in the December 2022 Supplemental Proposal to now include a step whereby the EPA will receive and review the super-emitter data from certified third-party notifiers before triggering any obligation on the part of the owner or operator. The final rules require the third-party notifier to submit notifications to the EPA within 15 calendar days after detection of a super-emitter event to ensure timely notice and includes standards for the content of the notification to aid in the EPA's review of the data. Third-party notifications must be submitted into the Super Emitter Program Portal at https://www.epa.gov/super-emitter and must include the following:

• Unique Third-Party Notifier ID.
• Date of detection of the super-emitter event.
• Location of super-emitter event in latitude and longitude coordinates.
• Owner(s) or operator(s) of an oil and natural gas facility of any individual well site, centralized production facility, or compressor station within 50 meters of the latitude and longitude coordinates of the super-emitter event, if available, and the method used by the third party to identify the owner or operator.
• Identification of the detection technology and reference to the approval of the technology.

• Documentation ( e.g., imagery) depicting the detected super-emitter event and the site from which the super-emitter event was detected.

• Quantified emission rate of the super-emitter event in kg/hr.
• Attestation statement that the information submitted by the third-party notifier is true and accurate to the best of the notifier's knowledge.

Upon receiving a third-party notification of super-emitter data through the Super Emitter Program Portal, the EPA will evaluate the notifications for completeness and accuracy to a reasonable degree of certainty. When the EPA determines that a notification has met these conditions, the EPA shall assign the notification a unique notification identification number, provide the notification to the owner/operator. and post the notification, except for the owner/operator attribution, at www.epa.gov/super-emitter. This approach responds to comments asking that notice of super-emitter events be provided as quickly as possible, both to the public and the identified owner/operator, but also that the owner/operator have an opportunity to respond before the super-emitter event is publicly attributed to a particular owner/operator. The EPA shall post owner/operator attributions that have been confirmed through the responses received; where response submittal deadlines have passed but no responses have been received, the EPA intends to post owner/operator attributions that the EPA reasonably believes to be accurate.

d. Identification of a Super-Emitter Event

In the final rules, the owner or operator must initiate an investigation within 5 days after receiving an EPA notification of a super-emitter event and report the results to the EPA within 15 days after receiving such notification. If an owner or operator determines that they do not own or operate a well site, centralized production facility, or compressor station within 50 meters from the latitude and longitude provided in the notification, the owner or operator must report that to the EPA and the investigation is then complete. Otherwise, the owner or operator must investigate to determine the source of the super-emitter event.

As explained earlier in this section X.C, a super-emitter event may have been emitted from one or more of the following: (1) an affected facility or associated equipment ( e.g., a control device or CVS) subject to regulation under NSPS OOOO, OOOOa, or OOOOb (“NSPS sources”); (2) a designated facility or associated equipment subject to a state or Federal Plan promulgated pursuant to EG OOOOc (“EG sources”); or (3) an unregulated source ( i.e., one that is not (1) or (2) above). Therefore, the investigation is not limited to NSPS or EG sources but also includes other sources that the owner or operator may suspect could be the source of the super-emitter event.

The owner or operator must investigate and report to the EPA the results of the investigation within 15 days after receiving a notification from the EPA. The owner and operator must also maintain a record of these investigations. To provide confidence in the reported information, the final rule has updated the list of investigations that the EPA believes will most likely reveal the source of the super-emitter event. Because the relevant investigations for identifying the source(s) of the super-emitter event may vary depending on what the third-party data reveals, the final rules defer to the owner and operator in deciding the appropriate investigation(s). However, where there are affected or designated facilities or associated equipment onsite, the owner and operator may conclude that they are unable to identify the source of the super-emitter event only after having conducted the applicable investigation listed in the respective final rule for each affected or designated facility and associated equipment.

The list of potential actions to identify the potential cause of super-emitter events may include but are not limited to the following:

• Review any maintenance activities ( e.g., liquids unloading) or process activities starting from the date of detection of the super-emitter event as identified in the notification.

• Review all monitoring data from control devices ( e.g., flares) over the same time period.

• Review any fugitive emissions survey performed under a fugitive emissions monitoring plan over the same time period.
• Review data from any continuous alternative technology systems over the same time period.
• Screen the entire well site, centralized production facility, or compressor station with OGI, EPA Method 21, or an alternative test method(s).

e. Super-Emitter Event Report

As was proposed, the final rules require that the owner or operator submit a report to the EPA within 15 days after receiving a Super-Emitter Event notification through the Super Emitter Program Portal, including an attestation that the report is complete and accurate. The report must include the following information:

• Notification Report ID

• Confirmation that you are the owner or operator of the oil and gas facility within the immediate area ( i.e., 50 meters) of the latitude and longitude provided in the notification. If you do not own or operate an oil and gas facility within 50 meters of the of the latitude and longitude provided in the notification, you are not required to provide the additional information described below.

• General identification for the facility, including physical address and applicable ID ( e.g., EPA ID Number, American Petroleum Institute (API) Well ID) and the responsible official.

• Whether there are affected facilities or associated equipment subject to NSPS OOOO, OOOOa or OOOOb or designated facilities or associated equipment subject to a state or Federal plan pursuant EG OOOOc.
• Attestation that investigations were conducted to verify the presence or the absence of a super-emitter event.

• If you were unable to identify the source of the super-emitter and if there are NSPS OOOO, OOOOa or OOOOb affected facilities or associated equipment, or designated facilities or associated equipment subject to a state or Federal plan pursuant EG OOOOc, onsite, confirmation that you have conducted all investigations listed in the Super Emitter Program (as specified above in section X.C.2.d) that are applicable to such affected or designated facilities and associated equipment.

• If a super-emitter source is identified, what the source is and whether it is (i) an affected facility or associated equipment subject to NSPS OOOO, OOOOa, or OOOOb or (ii) a designated facility or associated equipment subject to a state or Federal plan under EG OOOOc.
• If a super-emitter event is found, the date and time the super-emitter event ended.

Upon receiving this information from the owner or operator, the EPA will update the notification report with the information provided by the owner or operator and will make the updated report publicly available at www.epa.gov/super-emitter. If a super-emitter event emitted from an NSPS OOOO, OOOOa or OOOOb affected facility or associated equipment or a designated facility or associated equipment subject to a state or Federal plan pursuant EG OOOOc, or associated equipment, is ongoing, you are also required to report to the Super Emitter Program Portal the following information:

• A short narrative on how you intend to end the super-emitter event, including the targeted date for completion.
• Within 5 days after the super-emitter event has ended, the date and time the super-emitter event ended.

As discussed earlier in this section X.C, CAA 114(a) gives the EPA broad authority to require that owners and operators investigate and report all sources that they suspect may have caused or contributed to the super-emitter event specified in the EPA notice that they have received under the Super Emitter Program. CAA 114(a) does not require regulatory text for the EPA to exercise its information gathering authority under CAA 114(a), and the EPA believes that adequate notice is provided in this Federal Register document, which clearly sets forth the required investigations and reporting requirements under the Super Emitter Program and their applicability to all oil and gas emission sources, whether or not they are subject to any applicable CAA section 111 standard. Nevertheless, to facilitate the implementation of the Super Emitter Program, the EPA has codified provisions of the Super Emitter Program into the regulatory text of the new NSPS OOOOb and, as appropriate, in the model rule implementing EG OOOOc and amendments to NSPS OOOO and OOOOa. Specifically, NSPS OOOOb provides the major framework for the Super Emitter Program, including criteria for certifying third-party notifiers, criteria for third-party notifications to the EPA, and provisions governing the EPA's notification of identified owners and operators. In addition, NSPS OOOOb includes regulatory text governing the investigation and reporting as they relate to NSPS OOOOb affected facilities and associated equipment. Similarly, the EPA has amended NSPS OOOO and OOOOa to include super-emitter event investigation and reporting requirements as they relate to affected facilities and associated equipment under those NSPS. Such provisions are also included in the model rule implementing EG OOOOc. In addition, both NSPS OOOOb and the model rule implementing EG OOOOc includes a requirement to repair fugitive component(s) that owners and operators have identified as the source of super-emitter event specified in the EPA notice; as explained earlier in this section X.C, the standards for fugitive emissions components affected facilities under NSPS OOOOb (and presumptive standards under EG OOOOc) include a requirement to repair fugitive component(s) that owners and operators have identified as the source of super emitter-event specified in the EPA notice.

Further, pursuant to the Paperwork Reduction Act (PRA), the EPA estimated the reporting burden under the Super Emitter Program when it issued the December 2022 Supplemental Proposal. The total burden presented in section XVII.B for NSPS OOOOb of this final preamble includes the reporting burden for the entire Super Emitter Program, including reporting pertaining to affected facilities under NSPS OOOO and NSPS OOOOa and non-NSPS sources. The estimated reporting burden for the final Super Emitter Program has not changed since the December 2022 Supplemental Proposal and includes the estimated burden of required activities under the Super Emitter Program such as third-party certifications and notifications to the EPA and reporting requirements for identified owners and operators. Both the supplemental proposal and this final rulemaking have been reviewed by the Office of Management and Budget (OMB) through the interagency review process. The EPA envisions that for simplicity, completeness, and transparency, owners and operators would prefer one comprehensive Super Emitter Program over the possibility of having to respond to two EPA notices on a super-emitter event.

D. Process Controllers

Process controllers are automated instruments used for maintaining a process condition, such as liquid level, pressure, pressure difference, or temperature. In the oil and gas industry, many process controllers are powered by pressurized natural gas and emit natural gas to the atmosphere. However, process controllers may also be powered by electricity or compressed air, and these types of controllers do not use or emit natural gas. Natural gas-driven process controllers are a significant source of methane emissions. For instance, in the 2019 GHGRP, methane emissions from process controllers made up 65 percent of the total methane emissions from petroleum system onshore production and 28 percent of the total methane emissions from natural gas systems onshore production.

In the December 2022 Supplemental Proposal, the EPA proposed a “zero emissions” VOC and methane standard in NSPS OOOOb and a “zero emissions” methane presumptive standard in EG OOOOc. This standard can be achieved by using a process controller that is not powered by natural gas, by capturing the emissions from the natural gas-driven controllers and routing them to a process, or by using self-contained controllers. The proposed rules included an exemption from the zero-emissions requirement for process controllers in Alaska at locations where access to electrical power from the power grid is not available. The proposed requirements for these sources in Alaska were to use lower emitting natural gas-driven process controllers and to perform inspections to ensure that they are operating properly. While there are changes to some compliance aspects in the final rules, such as a further-out compliance date than proposed with an interim standard for the NSPS, the zero-emissions standard in NSPS OOOOb and presumptive standard in EG OOOOc (with the Alaska exemption) are being finalized as proposed.

1. NSPS OOOOb

a. Affected Facility

The standards apply to the collection of new, modified, and reconstructed natural gas-driven process controllers at a site ( i.e., a well site, centralized production facility, onshore natural gas processing plant, or compressor station). Process controllers that are emergency shutdown devices (ESD) or that are not natural gas-driven are not included in the affected facility.

b. Final Standards

The standards that apply differ depending on the location of the site and whether access to electrical power is available at the site, which are sites that have commercial line power onsite. For any site outside of Alaska, the standard for all process controllers is zero emissions of VOC and GHG (in the form of methane). Zero emissions of VOC and GHG may be achieved by using process controllers that are not driven by natural gas (and thus not affected facilities), by routing natural gas-driven process controller vapors through a closed vent system to a process, by using self-contained natural gas-driven process controllers, or by another means that achieves the numerical standard of zero emissions of GHG (in the form of methane) and VOC. For sites in Alaska with access to electrical power the standard for all process controllers at the site is also zero emissions of VOC and GHG. For sites in Alaska without access to electrical power, owners/operators must use natural gas-driven process controllers with low natural gas emission rates. These process controllers include continuous bleed controllers with an emissions rate (or bleed rate) of less than or equal to 6 standard cubic feet per hour (scfh) and intermittent vent controllers, which are process controllers that only emit natural gas when they actuate, rather than emitting continuously. Intermittent vent controllers are subject to monitoring requirements explained below. Further, as an optional alternative, sites in Alaska without access to electrical power may route emissions from natural gas-driven process controllers to a control device achieving a 95 percent emissions reduction. Table 12 summarizes the emissions standards for process controllers.

Based on comments expressing concerns about new sources' ability to obtain the equipment necessary to demonstrate compliance with the final standard of zero emissions immediately upon the effective date of the final rule, the EPA is finalizing a NSPS compliance deadline for process controllers that allows for up to 1 year from the effective date of the final rule. This means that new sources will have up to 1 year to come into full compliance with the final standard of zero emissions. Until that final date of compliance, owners and operators must demonstrate compliance with an interim standard which mirrors the requirements for sites in Alaska that do not have access to electrical power. This topic is explained in detail in section XI.D.4 below.

c. Monitoring Requirements

Monitoring is required for most natural gas-driven process controllers. For self-contained process controllers, initial and periodic monitoring is required to demonstrate that there are no identifiable emissions from the process controller. For intermittent process controllers (allowed at sites in Alaska without access to electrical power), initial and periodic monitoring is required to demonstrate that there are no identifiable emissions from the process controller when the process controller is idle. For process controllers that have emissions routed through a closed vent system to a process or to a control device, initial and periodic monitoring is required to demonstrate that there are no identifiable emissions from the closed vent system. In addition to the closed vent system monitoring requirements, process controllers that have emissions routed through a closed vent system to a control device (allowed at sites in Alaska without access to electrical power) must perform the monitoring specified in 40 CFR 60.5417b for the particular type of control device that is used. As further discussed in sections X.H and XI.H of this document, each control device must have a continuous parameter system installed and a continuous recording device for the monitoring results. Enclosed combustion devices and flares also must have either periodic visible emissions inspections or use a surveillance camera system to monitor for visible emissions. A summary of the required monitoring for natural gas-driven process controllers is shown in table 13.

d. Recordkeeping and Reporting Requirements

Owners or operators of a process controller affected facility are required to submit information about the affected process controller facility in annual reports. The information required for the first annual report includes an identification of each natural gas-driven controller included in the process controller affected facility and an identification of the emissions standards compliance method that will be used for the affected facility. The initial annual report must also include a demonstration that a natural gas-driven process controller with a bleed rate greater than 6 scfh is required if such a process controller is used in Alaska at a site without access to electricity (the standard allows a process controller with a bleed rate greater than 6 scfh in certain circumstances), and also a certification that the closed vent system is adequately designed if a closed vent system is used for a process controller affected facility. After the initial annual report, this information about the affected facility is only required to be submitted in the annual report if there are changes to the previously submitted information. Each annual report must include the dates and results of inspections conducted for self-contained and intermittent vent natural gas-driven process controllers, inspections of closed vent systems (for sites routing emissions to a process or sites in Alaska routing emissions to a control device), monitoring and inspections of control devices (for sites in Alaska using a control device to reduce emissions by 95 percent), and information for any deviations from the process controller emissions standards that occurred during the reporting period.

Owners and operators are also required to keep records of the information submitted in the annual reports regarding the process controller affected facility, and if applicable, the records required for monitoring and inspections of closed vent systems, control devices, self-contained process controllers, and intermittent vent process controllers. Records of each deviation must also be kept.

2. EG OOOOc

a. Designated Facility

The final EG define designated facilities for purposes of process controllers as the collection of existing natural gas-driven process controllers at a well site, centralized production facility, onshore natural gas processing plant, or compressor station. Process controllers that are emergency safety devices (ESD) or that are not natural gas-driven are not included in the designated facility.

b. Final Presumptive Standards

The presumptive methane standards for existing sources under EG OOOOc are the same as the final methane standards for new sources under NSPS OOOOb.

c. Monitoring Requirements

The monitoring requirements in EG OOOOc are the same as those for NSPS OOOOb.

d. Recordkeeping and Reporting Requirements

The recordkeeping and reporting requirements in EG OOOOc are the same as those for NSPS OOOOb.

E. Pumps

In the oil and natural gas industry, pumps are used for many purposes, including chemical injection, hot glycol circulation for heat tracing/freeze protection, and glycol circulation in dehydrators. These pumps are generally either piston pumps or diaphragm pumps that can be powered by compressed air, compressed natural gas, or electricity. Of these pumps, those that are pneumatic units driven by natural gas emit methane and VOC to the atmosphere as part of their normal operation. In many situations across all segments of the oil and gas industry, natural gas-driven pneumatic pumps are used where electricity is not readily available.

In the December 2022 Supplemental Proposal, the proposed standard in NSPS OOOOb and presumptive standard in EG OOOOc was zero emissions of methane and VOC. The proposed standards may be achieved by the use of pumps not powered by natural gas. In that situation, the pump would not be an affected or designated facility because it would not be powered by natural gas. For sites in the production or transmission and storage segment of the industry without access to electricity from the power grid, the proposed standards in the December 2022 Supplemental Proposal included a complex hierarchical structure that allowed the use of natural gas-driven pumps in certain situations based on the technical feasibility of pump control measures and the existence of situations that would allow the emissions to be routed to a process or to a control device already on a site. In the final rule, the complex hierarchical structure has been removed, and final NSPS OOOOb and EG OOOOc (presumptive standard) specify zero emissions for all pumps except those at sites without access to electricity with fewer than three natural gas-driven diaphragm pumps. For those sites, the final standards in NSPS OOOOb and presumptive standards in EG OOOOc are based on whether an existing situation exists that allows the emissions to be routed to a process or to a control device already on site.

1. NSPS OOOOb

a. Affected Facility

The pump standards apply to the collection of new, modified, and reconstructed natural gas-driven pumps at a well site, centralized production facility, onshore natural gas processing plant, or compressor station. Pumps that are in operation less than 90 days per calendar year or that are not natural gas-driven are not included in the affected facility.

b. Final Standards

The standards that apply differ depending on the number of natural gas-driven diaphragm pumps at the site ( i.e., well site, centralized production facility, onshore natural gas processing plant, or compressor station) and whether the site has access to electrical grid power. For any site with access to electrical power and for sites without access to electrical power that have three or more natural gas-driven diaphragm pumps, the standard for all pumps in the affected facility is zero emissions of VOC and GHG (in the form of methane). Zero emissions of VOC and GHG may be achieved by either using pumps that are not driven by natural gas (and are therefore not affected facilities), by routing natural gas-driven pump vapors through a closed vent system to a process, or by other means that achieves the standard of zero emissions. For sites without access to electrical power that have fewer than three diaphragm pumps (two or one), the standards require that GHG and VOC emissions from all natural gas-driven pumps in the affected facility be routed to a process if a vapor recovery unit (VRU) is onsite. If a VRU is not onsite, emissions must be reduced by 95 percent if a control device with at least this emissions reduction capability is already available onsite, or be reduced by less than 95 percent if a control device is onsite but is not capable of reducing GHG and VOC emissions by 95 percent or more. Table 14 summarizes the emissions standards for pumps.

Just as with process controllers, and based on comments expressing concerns about new sources' ability to obtain the equipment necessary to demonstrate compliance with the final standard of zero emissions immediately upon the effective date of the final rule, the EPA is finalizing a NSPS compliance deadline for pumps that allows for up to 1 year from the effective date of the final rule. This means that new sources will have up to 1 year to come into full compliance with the final standard of zero emissions. Until that final date of compliance, owners/operators must demonstrate compliance with an interim standard which mirrors the requirements for pumps at sites without access to grid electricity that have fewer than three diaphragm pumps found at 40 CFR 60.5393b(b). This topic is explained in detail in section XI.E.2 below.

c. Monitoring Requirements

Monitoring is required for pump affected facilities that have emissions routed to a process or control device. For these affected facilities, initial and periodic monitoring is required to demonstrate that there are no identifiable emissions from the closed vent system. In addition to the closed vent system monitoring requirements, pumps that have emissions routed through a closed vent system to a control device reducing emissions by 95 percent or more must perform the monitoring specified in 40 CFR 60.5417b for the particular type of control device that is used. As further discussed in sections X.H and XI.H of this document, each control device must have a continuous parameter system installed and a continuous recording device for the monitoring results. Enclosed combustion devices and flares also must have either periodic visible emissions inspections or use a surveillance camera system to monitor for visible emissions. A summary of the required monitoring for pump affected facilities is shown in table 15.

d. Recordkeeping and Reporting Requirements

Owners or operators of a pump affected facility are required to submit information about the affected pump facility in annual reports after becoming subject to NSPS OOOOb. The information required for the first annual report includes an identification of each natural gas-driven pump included in the pump affected facility and an identification of the emissions standards compliance method that will be used for the affected facility. The initial annual report must also include a certification that the closed vent system is adequately designed if a closed vent system is used for the pump affected facility. If complying by using a control device that achieves less than 95 percent emissions control or if no control device will be used, owners or operators must include a certification that no control device is on site that is capable of achieving a 95 percent emissions reduction or a certification that no control device is present at the site. After the initial annual report, this information about the affected facility is only required to be submitted in the annual report if there are changes to the previously submitted information. Each annual report must include the dates and results of inspections conducted of closed vent systems, monitoring and inspections of control devices that reduce emissions by 95 percent or more, and information for any deviations from the pump emissions standards that occurred during the reporting period.

Owners and operators are also required to keep records of the information submitted in the annual reports regarding the pump affected facility, and if applicable, the records required for monitoring and inspections of closed vent systems and control devices. Records of each deviation must also be kept.

2. EG OOOOc

a. Designated Facility

These final EG define designated facilities as the collection of natural gas-driven pumps at a well site, centralized production facility, onshore natural gas processing plant, or compressor station. Pumps that are in operation less than 90 days per calendar year or that are not natural gas-driven are not included in the designated facility.

b. Final Presumptive Standards

The presumptive methane standards for existing sources under EG OOOOc are the same as the methane standards for new sources under NSPS OOOOb.

c. Monitoring Requirements

The monitoring requirements in EG OOOOc are the same as those for NSPS OOOOb.

d. Recordkeeping and Reporting Requirements

The recordkeeping and reporting requirements in EG OOOOc are the same as those for NSPS OOOOb.

F. Wells and Associated Operations

A well is a hole drilled for the purpose of producing oil or natural gas. Many of the sources covered by NSPS OOOOb and addressed by EG OOOOc are associated with processes and equipment that is used to handle, store, move, and process the oil and natural gas downstream of the well. There are three sources, however, that are more directly related to the well itself. These are well completions, liquids unloading from gas wells, and associated gas from oil wells. In the November 2021 Proposal, the EPA proposed separate NSPS OOOOb affected facility definitions for each of these three sources. The result of including all three definitions would have been that a single well could have three different affected facilities for three different emissions sources. In the December 2022 Supplemental Proposal, to eliminate the potential confusion from this complex regulatory structure, the EPA proposed to change its approach as part of the supplemental proposal. Rather than three separate well affected facilities, the EPA proposed a definition of well affected facility, which is defined as a single well. Separate standards were proposed for well completions, liquids unloading from gas wells, and associated gas from oil wells. This structure is retained in the final rule.

For existing sources, there will never be well completions, as that activity is only performed for newly constructed or reconstructed/modified wells. Therefore, the proposed EG OOOOc in the 2022 Supplemental Proposal included the same basic definition for well designated facility, but only included presumptive standards for liquids unloading from gas wells and associated gas from oil wells. This structure is also retained in the final EG OOOOc.

The following sections summarize the final NSPS OOOOb and EG OOOOc. Specifically, section X.F.1 addresses the affected facility and designated facility definitions, section X.F.2 addresses the standards and presumptive standards for associated gas wells, section X.F.3 addresses the standards and presumptive standards for liquids unloading, and section X.F.4 addresses the standards for well completions.

1. Well Affected and Designated Facility Definitions

a. NSPS OOOOb

Well affected facility. Each well affected facility, which is a single well.

(1) In addition to 40 CFR 60.14, a “modification” of an existing well occurs when:

(i) An existing well is hydraulically fractured, or

(ii) An existing well is hydraulically refractured.

b. EG OOOOc

Well designated facility. Each well designated facility, which is a single well.

2. Associated Gas From Wells Producing Primarily Oil

a. NSPS OOOOb

i. Affected Facility and Final Work Practice Standards

Each well affected facility that produces associated gas is subject to the standards, where associated gas is defined as natural gas which originates at wells operated primarily for oil production that is released from the liquid hydrocarbon during the initial stage of separation after the wellhead. For the purpose of distinguishing wells operated primarily for oil production that produce associated gas from wells operated primarily for gas production, the EPA refers to the former as associated gas wells in this final rule. To provide additional clarity regarding which wells are affected facilities subject to the associated gas standards, the EPA added a definition of associated gas to this final rule. In order to clearly distinguish associated gas from gas vented during well completion activities, the definition of associated gas specifies that associated gas production begins at the startup of production after the flow back period ends. Further, the EPA has chosen not to define oil wells or gas wells in NSPS OOOOb or EG OOOOc.

The NSPS OOOOb final rule separates new associated gas wells into multiple groups based on when construction is commenced. This grouping serves the purpose of a “phase-in” of the final rule standards which the EPA believes is appropriate in this situation because of certain changes that the EPA made to these standards between the December 2022 Supplemental Proposal and final rule. These groups are: (1) Wells that commence construction after May 7, 2026, (2) wells that commence construction between May 7, 2024 and May 7, 2026, and (3) wells that commenced construction between December 6, 2022, and May 7, 2024, and wells that are modified or reconstructed after December 6, 2022. The definition of “commenced” within the NSPS general provisions apply for purposes of the NSPS OOOOb. 40 CFR 60.2.

The final work practice standard for all three groups is largely the same. The associated gas must either be recovered from the separator and routed into a gas gathering flow line or collection system to a sales line, recovered from the separator and used as an onsite fuel source, recovered from the separator and used for another useful purpose that a purchased fuel, chemical feedstock, or raw material would serve, or recovered from the separator and reinjected into the well or injected into another well. The final work practice standard for wells in the second and third group, is very similar to what the EPA proposed in the December 2022 Supplemental Proposal, although there are certain limitations that were not included in the supplemental proposal, which we discuss below.

Wells in the first group ( i.e., those wells that commence construction after May 7, 2026) are required to route the gas to a sales line, use the gas as an onsite fuel source, for another useful purpose that a purchased fuel, chemical feedstock, or raw material would serve, or reinject it into the well or into another well upon start-up. The final standards do not allow these wells to routinely flare emissions because we have determined that, with advance planning, at least one of the options to avoid routine flaring will be feasible at such wells (including routing the gas to a sales line, using the gas as an onsite fuel source, using the gas for another useful purpose that a purchased fuel, chemical feedstock, or raw material would serve, or reinjecting it into the well or into another well). These sites must handle the associated gas using one of these options, but the final rule still includes provisions to allow short-term flaring for specific circumstances such as safety concerns. The EPA recognizes that this is a change from what was included in the December 2022 Supplemental Proposal because there the EPA proposed to allow certain wells to routinely flare provided they made a technical infeasibility demonstration that was certified. Because of this change at final, the EPA is applying this requirement (no routine flaring) to wells that commence construction later than 24 months after the effective date of this final rule. This additional time beyond the rule's effective date will provide owners and operators with a sufficient period to adjust to this change so that they can ensure compliance with the final standard as soon as the well starts to produce associated gas.

Wells in the second group ( i.e., wells that commence construction between May 7, 2024 and May 7, 2026) must comply with the final standard of no routine flaring on or before May 7, 2026. At that time, these wells will no longer be allowed to flare routinely with a showing of technical infeasibility, and must route associated gas to a sales line, use the gas for another useful purpose that a purchased fuel, chemical feedstock, or raw material would serve, or reinject the gas into the well or inject it into another well. In the interim period not to exceed 24 months from the effective date of the final rule, these wells may route the associated gas to a flare or control device that reduces methane and VOC emissions by at least 95.0 percent provided the owner/operator can demonstrate that the other control options discussed above are technically infeasible. Again, this will allow for a sufficient phase in period for owners and operators of wells in this group to adjust to the final standard, which is different than what the EPA included in the December 2022 Supplemental Proposal.

For wells in the third group (wells that commenced construction, modified, or reconstructed, between December 6, 2022 (the date that the supplemental proposal published in the Federal Register ), and May 7, 2024), the final rule allows routing the associated gas to a flare or control device that reduces methane and VOC emissions by at least 95.0 percent on a routine basis, provided that the owner or operator documents and certifies that routing the associated gas to a sales line, using it as onsite fuel or for another beneficial purpose, or injecting/reinjecting it are technically infeasible. This allowance for technical infeasibility is provided for a period of 1 year at a time. Owners and operators of wells in the third group must renew the technical infeasibility determination/certification annually to be able to continue to route the associated gas to a flare or control device.

Table 16 summarizes the different groups of associated gas wells under NSPS OOOOb for purposes of phasing in the final rule standards and when routine flaring is, or is not, allowed for each group.

When associated gas is routed to a flare or control device, the control device must meet all the requirements specified in 40 CFR 60.5412b. See section X.H of this preamble for more information on control device requirements, including requirements for flares. In addition, the CVS routing the associated gas to the flare or control device must comply with the provisions in 40 CFR 60.5411b(a) and (c).

The EPA recognizes that temporary situations can occur beyond the control of an owner/operator that could make it technically infeasible or unsafe to comply with the standard for a limited period of time. Therefore, for all wells subject to NSPS OOOOb, the final rule allows owners and operators to route the associated gas to a flare or control device temporarily. Specifically, the final rule allows this for the situations and durations shown in table 17.

The final rule requires that during any period when associated gas is temporarily routed to a flare, the owner or operator demonstrate that the flare is meeting the requirements in 40 CFR 60.5412b. See section X.H of this preamble for more information on control device standards.

The final rule also allows short-term venting in malfunction situations where flaring the associated gas would cause an unsafe environment. This venting would be limited to 12 hours.

As noted earlier in this preamble, for wells for which construction commenced between December 6, 2022, and May 7, 2024, and for wells that are reconstructed or modified after December 6, 2022, the final rule allows routinely routing the associated gas to a flare or control device that achieves 95.0 percent VOC and methane reduction provided a yearly technical infeasibility demonstration. This means routinely routing the associated gas to a flare or control device is allowed only if the owner or operator demonstrates that all four options included in the work practice standard discussed previously are infeasible due to technical reasons. In order to demonstrate such technical infeasibility, the final rule requires that a detailed analysis be performed, and that documentation be prepared that demonstrates the technical reasons for this infeasibility. The demonstration must address the technical infeasibility for all options identified in the rule, specifically: (1) Route into a gas gathering flow line or collection system to a sales line, (2) recover from the separator and use as an onsite fuel source, (3) recover from the separator and use for another useful purpose that a purchased fuel, chemical feedstock, or raw material would serve, or (4) recover from the separator and reinject into the well or injected into another well.

The two components of a technical infeasibility demonstration are the list of technologies to be evaluated, and reason that each of technologies is infeasible. The first is the technologies or solutions to be evaluated. For three of the options—route into a gas gathering flow line or collection system to a sales line, recover from the separator and use as an onsite fuel source, reinject into the well or another well—this is straightforward. However, the third option—use the associated gas for another useful purpose that a purchased fuel, chemical feedstock, or raw material would serve—is more open ended.

The final rule does not specify the “other useful purpose” solutions that must be evaluated, but it is the responsibility of the owner and operator, along with the qualified professional engineer or other qualified personnel performing the evaluation, to ensure that the list of options evaluated is comprehensive to address technically viable solutions.

Technologies that are in the evaluation, pilot-plant, or testing stages are not considered to be technically viable.

In summary, to demonstrate technical infeasibility in order to route to a flare or control device, you must establish that it is not technically feasible to route the associated gas into a gas gathering flow line or collection system to a sales line, and not technically feasible to use the associated gas as an onsite fuel source such as a generator, fuel cell, or other power-producing use, and not technically feasible to reinject into the well or another well, and not technically feasible to utilize “other useful purposes” of the associated gas. A technically viable “other useful purpose” is likely to require the routing of the associated gas to on-site or nearby equipment that compresses, liquifies, or transforms the gas into a physical state that can be transported by pipeline or other transportation mode to an eventual user. A determination of technical infeasibility requires a showing of site-specific conditions that make these operations infeasible for even the most basic of such uses. One such basic use is capture and truck transportation offsite to a user or processing facility.

The second component of the demonstration is the determination that each of the possibilities is infeasible. While the final rule does not specify criteria for technical infeasibility, the EPA generally characterizes acceptable reasons in the general categories of physical, logistical, or legal factors. Examples could include, but are not limited to, the following. It may be infeasible to connect to a sales line because of inability to secure necessary easements and/or rights-of-way, inability to obtain necessary specialized equipment, inadequate capacity of gathering system to accept the gas, or production sharing contract restrictions. It may be infeasible to use the associated gas as an onsite fuel source because there are no onsite power needs or power needs have been met with less gas than produced, there is insufficient associated gas to support a small electricity generation plant, and there is no local demand for the power. Note that it would be difficult to claim technical infeasibility based on no onsite power needs if the site has equipment that is burning diesel or other fuel which could be replaced by using the associated gas. Reinjection may be infeasible because there is no subsurface reservoir or other storage available for reinjection in the vicinity. To demonstrate that the “other beneficial use” option is not technically feasible an owner or operator could show that there is an observable or demonstrable reason that the operator cannot install equipment to convert associated gas to compressed natural gas (CNG) at the well site due to physical or technical constraints and/or that CNG transport in the region is not available. It is expected that owners and operators will conduct detailed evaluations of all such options. The analysis must show clear evidence that the owner and operator has conducted due diligence to understand the situations where the solution is being successfully utilized and a demonstration of why it is not feasible at their site. Note that the EPA acknowledges that the unavailability of a solution, even one that has been demonstrated at one or more sites in the U.S., is a valid reason for an infeasibility conclusion. One overarching factor that may impact technical feasibility is the composition of the gas. The EPA recognizes that there are situations ( e.g., high sulfur content, high CO₂ and low methane content) where some solutions may be infeasible.

Each infeasibility demonstration must be certified by a qualified professional engineer or other qualified individual with expertise in the uses of associated gas. This certification must state: “I certify that the assessment of technical and/or safety infeasibility was prepared under my direction or supervision. I further certify that the assessment was conducted, and this report was prepared, pursuant to the requirements of 40 CFR 60.5377b(b)(1). Based on my professional knowledge and experience, and inquiry of personnel involved in the assessment, the certification submitted herein is true, accurate, and complete.”

Where available, each properly executed infeasibility determination and certification allows the owners and operators of that particular well site to routinely flare the associated gas for a one-year period. While some new and modified sites can make such showings to routinely flare, this mechanism is not available to all new well sites. See table 16 above. In the fast-moving landscape of the oil and natural gas industry, there are a variety of factors that could change the circumstances present when the previous infeasibility determination was performed. For example, a gathering system could have been built or extended in the vicinity of the well, the site could have expanded operations and have a need for onsite power, or a new commercially viable solution could become available. For this reason, the final rule requires that an updated infeasibility determination and certification be performed each year and submitted in the annual compliance report. If an option that was technically infeasible before has since become available, meaning that the reason that such option was technically infeasible before has changed in a way that the option is now feasible, then the owner/operator of the well must utilize that option going forward and must cease routine flaring.

ii. Recordkeeping and Reporting Requirements

For affected facilities, required records include documentation of the specific type(s) of compliance methods used ( i.e., routed into a gas gathering flow line or collection system to a sales line, used as an onsite fuel source, used for another useful purpose that a purchased fuel or raw material would serve, reinjected into the well or injected into a another well). For those temporary situations where the associated gas must be routed to a flare or control device, owners/operators must document the reason for this temporary flaring, along with the duration. If the gas is routed to a flare either on a temporary or routine basis, records must be kept demonstrating that flares meet the requirements outlined in 40 CFR 60.5412b. This information must also be reported in the annual report. For those temporary situations where the associated gas is vented due to malfunction situations where flaring or routing to a control device would cause an unsafe environment, the owner or operator must document the reason for this venting, along with the duration, the volume of gas vented, and the VOC and methane emissions. The annual report must include all information for each venting episode.

For wells that properly demonstrate technical infeasibility and therefore routinely route the associated gas to a flare or control device that achieves 95.0 percent reduction in VOC and methane, detailed records must be maintained supporting the infeasibility determination due to technical reasons, along with the signed certification by a qualified professional engineer or other qualified individual. This information must also be included in the annual report. As discussed previously, this demonstration and certification is required to be updated annually.

In addition, all records associated with a demonstration of proper design and operation of the control device, where used, must be maintained (see section X.H of this preamble). For all instances where associated gas is temporarily vented due to malfunction situations where flaring or routing to a control device would cause an unsafe environment, an owner or operator must also document the reason for this venting, along with the duration, the volume of gas vented, and the VOC and methane emissions. The annual report must include all information for each venting episode.

b. EG OOOOc

i. Designated Facility

Consistent with the NSPS OOOOb affected facility, each existing well that produces associated gas which commenced construction before December 6, 2022, is a designated facility for purposes of EG OOOOc. Associated gas is defined as natural gas which originates at wells operated primarily for oil production that is released from the liquid hydrocarbon during the initial stage of separation after the wellhead. To distinguish associated gas from gas vented during the completion activities, the definition of associated gas specifies that associated gas production begins at the startup of production after the flow back period ends.

ii. Final Work Practice Presumptive Standards

The final EG separates (subcategorizes) existing oil wells with associated gas into two groups based on the amount (mass) of methane in the associated gas. The demarcation between these two groups is 40 tons of methane per year. The presumptive standard in the final EG for wells that produce associated gas with over 40 tpy of methane is the same as what the EPA proposed for existing sources within the 2022 Supplemental Proposal.

The presumptive standard for existing wells that produce associated gas with over 40 tpy of methane is summarized as follows. For these sites, the associated gas must either be recovered from the separator and routed into a gas gathering flow line or collection system to a sales line, recovered from the separator and used as an onsite fuel source, recovered from the separator and used for another useful purpose that a purchased fuel, chemical feedstock, or raw material would serve, or recovered from the separator and reinjected into the well or injected into another well. If all of these options are technically infeasible, then these existing wells (producing associated gas with more than 40 tpy of methane) can route associated gas to a flare or control device that achieve 95.0 percent reduction in methane. The determination of technical infeasibility must be certified by a professional engineer or other qualified personnel, the flare or control device must meet the requirements of 40 CFR 60.5412b, and technical infeasibility must be re-certified on an annual basis. For purposes of this presumptive standard, the EPA intends that technical infeasibility be defined in the same manner as explained above for new sources. See the discussion under the NSPS (see section X.F.1 of this document) related to the requirements for an infeasibility determination and certification.

The presumptive standard in the final EG for wells that produce associated gas with 40 tpy of methane or less is to route associated gas to a flare or control device that achieves 95.0 percent reduction in methane. The difference between the two groups is that, for those existing wells with annual methane in the associated gas greater than 40 tpy, owners and operators are required to demonstrate that it is infeasible for technical reasons to utilize any of the work practice options before they can route associated gas to a flare or control device. For existing wells that produce associated gas containing 40 tpy or less of methane, flaring or routing to control is allowed without an infeasibility determination and certification. However, existing wells that produce associated gas containing 40 tpy or less of methane can still utilize any of the control options that result in zero emissions to meet the standard.

The EPA has created subcategories for designated facilities because EPA's analysis conducted after reviewing comments on the 2022 Supplemental Proposal indicates that it is not reasonable with respect to cost to require sources that produce less than 40 tpy methane of associated gas to route their associated gas to a sales line. The EPA analyzed the task of routing to a sales line and found that the two factors that controlled whether routing to a sales line was BSER was the distance that a pipeline would need to go to reach the sales line, and the amount of gas that could be recovered as measured at the separator. Over even short distances, the cost of routing to a sales line was not reasonable at very low levels of available associated gas. Given this and the comments that we received on this point, the EPA agreed with commenters that at low levels of associated gas production the flaring of associated gas is the BSER. See the final rule TSD chapter 3 on Associated Gas for further information on the determination of BSER for designated sources.

In order to determine whether the methane contained in the associated gas is 40 tpy or less, owners and operators must utilize a gas-to-oil ratio (GOR)-based method derived from paragraphs 40 CFR 98.234(m)(1) through (4) of GHGRP subpart W. Sources with methane contained in the associated gas greater than 40 tpy, and sources with methane contained in the associated gas 40 tpy or less that elect to comply with one of the work practices, are not required to calculate and document the annual methane content in the associated gas.

iii. Recordkeeping and Reporting

The recordkeeping and reporting requirements included in EG OOOOc are the same as those included in the NSPS OOOOb. Wells that elect to demonstrate that the methane contained in the associated gas is 40 tpy or less are required to maintain records of this calculation and submit it in the annual reports.

3. Gas Well Liquids Unloading Operations

a. NSPS OOOOb

i. Affected Facility

Each well affected facility gas well that undergoes liquids unloading.

ii. Final Standards

Each affected gas well that unloads liquids is required to employ techniques or technology(ies) that minimize or eliminate venting of emissions during liquids unloading events to the maximum extent. For the EPA's rationale for prescribing a work practice standard over a numeric standard, see section XI.F.3.a of this preamble. Owners or operators are also allowed the option to comply with the GHG and VOC standards by reducing methane and VOC emissions from each gas well liquids unloading event by 95 percent by routing emissions to a control device via a CVS.

For unloading technologies or techniques that eliminate venting of emissions during liquids unloading events, the final rule requires minimal recordkeeping and reporting.

For unloading technologies or techniques that could result in venting to the atmosphere, the final rule requires work practices be followed. Specifically, the final rule requires that owners or operators employ and document best management practices to minimize or eliminate venting of methane and VOC emissions for each gas well liquids unloading operation.

Specifically, owners or operators of well affected facilities that are gas wells that unload liquids must develop, maintain, and follow a best management practice plan to eliminate or minimize venting of methane and VOC emissions to the maximum extent possible from each gas well liquids unloading operation. This best management practice plan must meet the following minimum criteria: (1) Include steps that create a differential pressure to minimize the need to vent a well to unload liquids; (2) include steps to reduce wellbore pressure as much as possible prior to opening the well to the atmosphere; (3) unload liquids through the separator where feasible; and (4) close all wellhead vents to the atmosphere and return the well to production as soon as practicable.

The best management practice plan that provides steps to minimize or eliminate venting of emissions would apply for both planned venting events and unintended/unplanned venting events due to malfunctions or error. In some instances, depending on the non-venting liquids unloading technology or technique employed, the best management plan for planned and unplanned events may differ. In such cases, an owner or operator may choose to develop a separate plan to cover unplanned events. However, to minimize emissions, depending on technology or technique employed, the same minimum best management practice criteria should apply, i.e.: (1) Include steps that create a differential pressure to minimize the need to vent a well to unload liquids; (2) include steps to reduce wellbore pressure as much as possible prior to opening the well to the atmosphere; (3) unload liquids through the separator where feasible; and (4) close all wellhead vents to the atmosphere and return the well to production as soon as practicable. Where a planned or unplanned event occurs where best management practices were unable to be followed, an owner or operator is required to report those events as deviations. Specifically, owners or operators are required to report the number of liquids unloading events during the year where deviations from your best management practice plan occurred, the date and time the deviation began, the duration of the deviation in hours, documentation of why best management practice plan steps were not followed, and what steps, in lieu of your best management practice plan steps, were followed to minimize emissions to the maximum extent possible.

For owners or operators that comply with the GHG and VOC standards by reducing methane and VOC emissions from each gas well liquids unloading event by 95 percent by routing emissions to a control device via a CVS, an owner or operator is required to maintain records and report that it is complying by using this option. In instances where a deviation from the standard has occurred during the reporting period, an owner or operator would be required to provide information on the date and time the deviation began, the duration of the deviation, and a description of the deviation. Additionally, the dates of each cover and CVS inspection, whether emissions are identified, and the date of repair or the date of anticipated repair if repair is delayed would be required in the annual report. Where bypass requirements apply, the date and time of each bypass alarm or each instance the key is checked out would be included in the annual report. For the reports and records that must be maintained to demonstrate proper design and operation of the control device, see sections X.H.1 and X.H.2 of this preamble.

iii. Recordkeeping and Reporting Requirements

For each gas well liquids unloading operation where the technique/technology employed eliminates venting to the atmosphere, owners or operators are only required to maintain the identification of the well affected facility and the zero-emitting technology or technique used; and the number of liquids unloading events conducted during the reporting period that had unplanned venting events (if any) that required that they employ best management practices to minimize emissions to the maximum extent possible during the unplanned event. As noted previously, any unplanned venting events would be subject to the required best management practices and associated recordkeeping and reporting requirements for those events.

For each gas well liquids unloading operation where emissions are vented to the atmosphere, owners or operators of affected facilities are required to keep the following records: (1) Identification of each well affected facility that conducted liquids unloading during the reporting period that vented to the atmosphere; (2) the number of liquids unloading events during the reporting period that vented to the atmosphere; (3) documentation of your best management practice plan developed that meets the criteria specified in 40 CFR 60.5376b(d) of the final NSPS OOOOb; (4) a log of each best management practice plan step taken to minimize emissions to the maximum extent possible for each gas well liquids unloading event; and (5) documentation of each gas well liquids unloading event where deviations from your best management practice plan steps occurred, the date and time the deviation began, the duration of the deviation, documentation of best management practice plans steps were not followed, and the steps taken in lieu of your best management practice plan steps during those events to minimize emissions to the maximum extent possible. These requirements apply for both planned and unintended/unplanned venting events due to malfunctions or error.

For each well affected facility where gas well liquids unloading operations are conducted, an annual report is required to include a summary of the information required to be maintained.

b. EG OOOOc

i. Designated Facility

Each well designated facility gas well that undergoes liquids unloading.

ii. Final Presumptive Standards and Recordkeeping and Reporting Requirements

The work practice standards and recordkeeping and reporting requirements for well designated facilities that undergo gas well liquids unloading under EG OOOOc are the same as those finalized for NSPS OOOOb.

4. Well Completions

a. NSPS OOOOb

i. Affected Facility

Each well affected facility well completion of hydraulically fractured (or refractured) wells.

ii. Final Standards

For well completion of hydraulically fractured (or refractured) wells, there are two subcategories of hydraulically fractured wells for which well completions are conducted: (1) Non-wildcat and non-delineation wells (subcategory 1 wells); and (2) wildcat and delineation wells, and non-wildcat and non-delineation low-pressure wells (subcategory 2 wells). A wildcat well is a well drilled outside known fields or is the first well drilled in an oil or gas field where no other oil and gas production exists. A delineation well is a well drilled to determine the boundary of a field or producing reservoir.

For non-wildcat and non-delineation wells (subcategory 1 wells), owners or operators are required to use a combination of reduced emissions completion (REC) equipment/practices and a completion combustion device to control emissions from a completion event. For each flowback stage ( i.e., initial flowback stage, separation flowback stage) of the well completion, the EPA specifies requirements in the final rule. During the initial flowback stage, owners or operators are required to route the flowback to a storage vessel or completion vessel (frac tank, lined pit, or other vessel) and separator. During the separation flowback stage, owners or operators are required to route all salable gas from the separator to a gas flow line or collection system, re-inject the gas into the well or another well, use the gas as an onsite fuel source or use for another useful purpose that a purchased fuel or raw material would serve. If technically infeasible to route recovered gas as specified previously, recovered gas must be combusted. All liquids, during the separation phase, must be routed to a storage vessel or well completion vessel, collection system, or be reinjected into the well or another well. The final rule requires the operator to have the separator available and to use the separator for the entirety of flowback, either by having the separator on-site or at a nearby centralized facility or well pad that services the well affected facility. A well that is not hydraulically fractured or refractured with liquids, or that does not generate condensate, intermediate hydrocarbon liquids, or produced water such that there is no liquid collection system at the well site is not required to have a separator on-site or at a centralized production facility or well pad that services the well completion well affected facility.

For each wildcat and delineation well, and non-wildcat and non-delineation low pressure wells (subcategory 2 wells), owners or operators must either: (1) Route all flowback to a completion combustion device equipped with a continuous pilot flame; or (2) route all flowback into one or more well completion vessels and commence operation of a separator unless it is technically infeasible for a separator to function. Gas recovered from the separator must be captured and routed to a completion combustion device equipped with a continuous pilot flame. Option (2) may only be used where the owner or operator is able to operate a separator, and the separator must be available (onsite or otherwise available for use) and must be used for the entirety of flowback. For both options (1) and (2), combustion is not required in conditions that may result in a fire hazard or explosion, or where high heat emissions from a completion combustion device may negatively impact tundra, permafrost, or waterways.

Oil wells with a gas-to-oil ratio less than 300 scf of gas per stock tank barrel of oil produced are well affected facilities but have no requirements other than to maintain records of the low GOR certification and a claim signed by the certifying official.

iii. Recordkeeping and Reporting Requirements

Owners or operators of a well affected facility must notify the Administrator no later than 2 days prior to the commencement of each well completion operation listing the anticipated date of the well completion operation. If an owner or operator is subject to state regulations that require advance notification of well completions and you have met those notification requirements, then you are considered to have met the advance notification requirements of the final rule.

Owners or operators of well affected facilities must maintain a log for each well completion operation at each well affected facility. The log must be completed daily for the duration of the well completion operation and must contain specified record information (see 40 CFR 60.5420b(c)(1)(iii)).

Annual reports are required to include general information for all well affected facility reports, and for each well affected facility subject to well completion requirements. Owners or operators are required to maintain records and report information regarding each well completion operation conducted during the reporting period, including the location of the well, type of well, duration of completion event, and information related to the well completion itself ( e.g., actions taken to mitigate emissions). Additionally, if venting occurs, the annual report is required to include the specific reasons for venting in lieu of capture or combustion, as well as any deviations recorded ( i.e., the date and time the deviation began, the duration of the deviation in hours, and a description of the deviation).

For each well affected facility that is an oil well with a gas-to-oil ratio less than 300 scf of gas per stock tank barrel of oil produced, the annual report must include a record of the well type ( i.e., wildcat well, delineation well, or low-pressure well) and supporting inputs and calculations, if applicable. The records required to be maintained by the owner or operator include: (1) A record of the analysis performed in order to make that claim, including but not limited to, GOR values for established leases and data from wells in the same basin and field; (2) the latitude and longitude of the well in decimal degrees to an accuracy and precision of five decimals of a degree using North American Datum of 1983; (3) the United States Well Number; and (4) a record of the claim signed by the certifying official.

For each well meeting affected facility claiming an exemption at 40 CFR 60.5375b(h) for a well modified in accordance with 40 CFR 60.5365b(a)(1)(ii) ( i.e., an existing well that is hydraulically refractured), the annual report must include a statement that the well completion operation requirements of 40 CFR 60.5375b(a)(1) through (3) were met. Records required to be maintained include: (1) A record of the latitude and longitude of the well in decimal degrees to an accuracy and precision of five decimals of a degree using North American Datum of 1983; (2) the United States Well Number; (3) the date and time of the onset of flowback following hydraulic fracturing or refracturing; and (4) a record of the claim that the well completion operation requirements of 40 CFR 60.5375b(a)(1) through (3) were met.

b. EG OOOOc

Because the fracturing or re- fracturing of an existing well would constitute a modification under NSPS OOOOb, it would make the existing well a well affected facility under NSPS OOOOb. Thus, no requirements are specified for well completions under EG OOOOc.

G. Centrifugal Compressors

1. NSPS OOOOb

a. Affected Facility

The centrifugal compressor affected facility is defined as a single centrifugal compressor. A centrifugal compressor located at a well site is not a centrifugal compressor affected facility under NSPS OOOOb. A centrifugal compressor located at a centralized production facility is a centrifugal compressor affected facility under NSPS OOOOb.

b. Final Standards

Centrifugal compressor affected facilities with wet seals must comply with the GHG and VOC standards by reducing methane and VOC emissions from each centrifugal compressor wet seal fluid degassing system by 95 percent by routing emissions via a CVS to a control device. As an alternative to routing the CVS to a control device, an owner or operator may also route the CVS to a process. If an owner or operator chooses to comply with this requirement either by using a control device to reduce emissions or by routing to a process to reduce emissions, an owner must equip the wet seal fluid degassing system with a cover and the cover must be connected through a CVS meeting specified requirements, such as design and operation with no identifiable emissions.

For specified centrifugal compressors ( i.e., self-contained wet seal compressor, wet seal compressor equipped with a mechanical seal, centrifugal compressors equipped with sour seal oil separator and capture system, centrifugal compressors equipped with dry seals), an owner or operator has the option to comply with the rule by meeting the following work practice performance-based volumetric flow rate standards in lieu of requiring that emissions be routed to a control device or process:

(1) If an owner or operator uses a self-contained wet seal centrifugal compressor or a wet seal compressor equipped with a mechanical seal, an owner or operator must conduct monitoring and repair of the wet seal (as necessary) to maintain volumetric flow rate at or below 3 standard cubic feet per minute (scfm), in operating or standby pressurized mode, per seal. The volumetric flow rate of 3 scfm is an action level that, if exceeded, triggers the requirement to repair or replace the seal and is not a numeric limit.

(2) Owners or operators of centrifugal compressors on the Alaska North Slope that are equipped with a seal oil recovery system ( i.e., centrifugal compressors equipped with sour seal oil separator and capture system, such as a seal oil gas separation system that separates gas from the sour seal oil exiting the compressor seal assembly, upstream from the degassing drum) must conduct monitoring and repair of the wet seal (as necessary) to maintain a volumetric flow rate at or below 9 scfm (in operating or standby pressurized mode) per seal. The volumetric flow rate of 9 scfm is an action level that, if exceeded, triggers the requirement to repair or replace the seal and is not a numeric limit.

(3) If an owner or operator uses a centrifugal compressor equipped with a dry seal, an owner or operator must conduct monitoring and repair of the dry seal to maintain a volumetric flow rate at or below 10 scfm (in operating or standby pressurized mode) per seal. The volumetric flow rate of 10 scfm is an action level that, if exceeded, triggers the requirement to repair or replace the seal and is not a numeric limit. In addition to the volumetric flow rate monitoring required every 8,760 hours of operation, additional preventative (maintenance) or corrective measures may be required to maintain compliance with the centrifugal compressor wet and dry seal volumetric flow rate performance standard. Specifically, if the volumetric flow rate measured exceeds the flowrate specified for a centrifugal compressor seal, the seals connected to the measured vent must be repaired. Seal repair must be conducted within 90 calendar days from the date of the volumetric emissions measurement. If the repair of the wet or dry seal is technically infeasible, would require a vent blowdown, a compressor station shutdown, or would be unsafe to repair during operation of the unit, the repair can be delayed but must be completed during the next scheduled compressor station shutdown for maintenance, after a scheduled vent blowdown, or within 2 years, whichever is earliest. A vent blowdown is the opening of one or more blowdown valves to depressurize major production and processing equipment, other than a storage vessel. In addition, if the repair requires replacement of the compressor seal or a part thereof, but the necessary replacement seal or part cannot be acquired and installed within the repair timelines specified due to supplies being unavailable (where previously sufficiently-stocked), a delay of repair is allowed. However, in order to qualify for a delay of repair, the required seal or part replacement must be ordered no later than 10 calendar days after the centrifugal compressor seal is added to the delay-of-repair list due to parts unavailability.

Owners or operators must conduct volumetric flow rate measurements from each centrifugal compressor wet and dry seal vent within 15 days after the repair to document that the rate has been reduced to less than applicable flow rate per seal. If the individual seals are manifolded to a single open-ended vent line, the volumetric flow rate must be reduced to less than the sum of the individual seals multiplied by the applicable required flow rate per seal.

For the EPA's rationale for prescribing a work practice standard over a numeric standard, see section XI.G.2 of this preamble.

c. Recordkeeping and Reporting Requirements

For a centrifugal compressor affected facility complying by routing emissions from the wet seal degassing system to a process through a CVS, an owner or operator is required to maintain records and report that it is complying by using this option. In instances where a deviation from the standard has occurred during the reporting period, an owner or operator would be required to provide information on the date and time the deviation began, the duration of the deviation, and a description of the deviation. Additionally, they would be required to report of the dates of each cover and CVS inspection, whether emissions are identified, and the date of repair or the date of anticipated repair if repair is delayed would be included in the annual report. Where bypass requirements apply, the date and time of each bypass alarm or each instance the key is checked out would be included in the annual report.

For a centrifugal compressor affected facility complying by routing emissions from the wet seal degassing system to a control device through a CVS, an owner or operator is required to maintain records and report that it is complying by using this option. In instances where a deviation from the standard has occurred during the reporting period, an owner or operator would be required to provide information on the date and time the deviation began, the duration of the deviation, and a description of the deviation. Additionally, the dates of each cover and CVS inspection, whether emissions are identified, and the date of repair or the date of anticipated repair if repair is delayed would be required in the annual report. Where bypass requirements apply, the date and time of each bypass alarm or each instance the key is checked out would be included in the annual report. For the reports and records that must be maintained to demonstrate proper design and operation of the control device, see sections X.H.1 and X.H.2 of this preamble.

Owners or operators complying with a performance-based emissions standard for specified centrifugal compressors equipped with wet seals and dry seals must track and report in their annual report the cumulative number of hours of operation of each centrifugal compressor since startup, or since the previous screening/volumetric flow rate emissions measurement, as applicable. The annual report must also include a description of the method used and the results of the volumetric flow rate measurement or emissions screening, as applicable. Lastly, owners or operators must maintain records and report each measurement that exceeds the applicable performance-based emissions standard per seal during the reporting period, and the date and time the compressor seal was repaired to meet the required performance-based emissions standard per seal. In the case of delay of repair due to parts unavailability, operators must document the date the centrifugal compressor was added to the delay-of-repair list, the date the replacement seal or part thereof was ordered, the anticipated delivery date, and the actual delivery date; and the annual report needs to provide the reason for the needed delay and the date of anticipated repair.

2. EG OOOOc

a. Designated Facility

The centrifugal compressor designated facility is defined as a single centrifugal compressor. A centrifugal compressor located at a well site is not a centrifugal compressor designated facility under EG OOOOc. A centrifugal compressor located at a centralized production facility is a centrifugal compressor designated facility under EG OOOOc.

b. Final Presumptive Standards

For centrifugal compressor designated facilities with wet seals (including self-contained wet seal centrifugal compressors and centrifugal compressors equipped with mechanical seals) the presumptive GHG standards are work practice performance-based volumetric flow rate standards. These designated facilities must reduce methane emissions by maintaining a volumetric flow rate at or below 3 scfm (in operating or standby pressurized mode) per seal. Centrifugal compressors designated facilities operating on the Alaska North Slope that are equipped with a seal oil recovery system ( i.e., centrifugal compressors equipped with sour seal oil separator and capture system, such as a seal oil gas separation system that separates gas from the sour seal oil exiting the compressor seal assembly, upstream from the degassing drum) must maintain a volumetric flow rate at or below 9 scfm (in operating or standby pressurized mode) per seal. The volumetric flow rates of 3 and 9 scfm are action levels that, if exceeded, trigger the requirement to repair or replace the seal and are not numeric limits.

Centrifugal compressor designated facilities with dry seals must maintain a volumetric flow rate at or below 10 scfm (in operating or standby pressurized mode) per seal. The volumetric flow rate of 10 scfm is an action level that, if exceeded, triggers the requirement to repair or replace the seal and is not a numeric limit.

In addition to the flow rate monitoring required every 8,760 hours of operation, additional preventative (maintenance) or corrective measures may be required to maintain compliance. Specifically, if the volumetric flow rate measured exceeds the flowrate specified for a centrifugal compressor seal, the seals connected to the measured vent must be repaired. Seal repair must be conducted within 90 calendar days from the date of the volumetric emissions measurement. If the repair of the wet or dry seal is technically infeasible, would require a vent blowdown, would require a compressor station shutdown, or would be unsafe to repair during operation of the unit, the repair can be delayed but must be completed during the next scheduled compressor station shutdown for maintenance, after a scheduled vent blowdown, or within 2 years, whichever is earliest. A vent blowdown is the opening of one or more blowdown valves to depressurize major production and processing equipment, other than a storage vessel. In addition, if the repair requires replacement of the compressor seal or a part thereof, but the necessary replacement seal or part cannot be acquired and installed within the repair timelines specified due to supplies being unavailable (where previously sufficiently-stocked), a delay of repair is allowed. However, in order to qualify for a delay of repair, the required seal or part replacement must be ordered no later than 10 calendar days after the centrifugal compressor seal is added to the delay-of-repair list due to parts unavailability.

Owners or operators must conduct volumetric flow rate measurements from each centrifugal compressor wet and dry seal vent within 15 days after the repair to document that the rate has been reduced to less than applicable flow rate per seal. If the individual seals are manifolded to a single open-ended vent line, the volumetric flow rate must be reduced to less than the sum of the individual seals multiplied by the applicable required flow rate per seal.

Owners or operators must conduct volumetric flow rate measurements from each centrifugal compressor wet and dry seal vent within 15 days after the repair to document that the rate has been reduced to less than applicable flow rate per seal. If the individual seals are manifolded to a single open-ended vent line, the volumetric flow rate must be reduced to less than the sum of the individual seals multiplied by the applicable required flow rate per seal.

For the EPA's rationale for prescribing a work practice standard over a numeric standard, see section XI.G.2 of this preamble.

As an alternative, an owner or operator may reduce methane emissions from each centrifugal compressor wet seal fluid degassing system or dry seal system by 95 percent by routing emissions via a CVS to a control device, or by routing emissions via a CVS to a process. If an owner or operator chooses to comply with the requirement either by using a control device to reduce emissions or by routing to a process to reduce emissions, an owner or operator must equip the wet seal fluid degassing system with a cover and the cover must be connected through a CVS meeting specified requirements, such as design and operation with no identifiable emissions.

c. Recordkeeping and Reporting Presumptive Work Practice Requirements

Owners or operators complying with a performance-based emissions standard must track and report in their annual report the cumulative number of hours of operation of each centrifugal compressor since startup, or since the previous screening/volumetric flow rate emissions measurement, as applicable. The annual report must also include a description of the method used and the results of the volumetric flow rate measurement or emissions screening, as applicable. Lastly, owners or operators must maintain records and report each measurement that exceeds the applicable performance-based emissions standard per seal standard during the reporting period, and the date and time the compressor wet or dry seal was repaired to meet the applicable performance-based emissions standard. Where a delay of repair is needed, the annual report needs to provide the reason for the needed delay and the date of anticipated repair.

For a centrifugal compressor designated facility complying with the routing emissions from the wet seal compressor degassing system to a process through a CVS, an owner or operator is required to maintain records and report each centrifugal compressor during the reporting period that is complying by using this option. In instances where a deviation from the standard has occurred during the reporting period, an owner or operator would be required to provide information on the date and time the deviation began, the duration of the deviation, and a description of the deviation. Additionally, the dates of each cover and CVS inspection, whether emissions are identified, and the date of repair or the date of anticipated repair if repair is delayed would be included in the annual report. Where bypass requirements apply, the date and time of each bypass alarm or each instance the key is checked out would be included in the annual report.

For a centrifugal compressor designated facility complying with the routing emissions from the wet seal fluid degassing system to a control device through a CVS, an owner or operator is required to maintain records and report each centrifugal compressor during the reporting period that is complying by using this option. In instances where a deviation from the standard has occurred during the reporting period, an owner or operator would be required to provide information on the date and time the deviation began, the duration of the deviation, and a description of the deviation. Additionally, they would be required to report the dates of each cover and CVS inspection, whether emissions are identified, and the date of repair or the date of anticipated repair if repair is delayed. Where bypass requirements apply, the date and time of each bypass alarm or each instance the key is checked out would be included in the annual report. For the reports and records that must be maintained to demonstrate proper design and operation of the control device, see sections X.H.1 and X.H.2 of this preamble.

A. Combustion Control Devices

1. NSPS OOOOb

a. Compliance Assurance Requirements

NSPS OOOOb contains various compliance requirements to ensure that combustion control devices that are being used to meet a 95 percent emission reduction standard can continuously demonstrate this level of control of emissions from affected facilities. Except as noted in section XI.H of this preamble, the final compliance assurance requirements for combustion control devices reflect the requirements that were proposed in the December 2022 Supplemental Proposal. This section of the preamble presents a summary of the final requirements for combustion control devices.

Except for boilers and process heaters that introduce the vent stream with the primary fuel into the flame zone and flares, combustion control devices must demonstrate compliance with this control efficiency through a performance test, which must be repeated every 5 years. In lieu of conducting the initial performance test, owners and operators may purchase an enclosed combustion device that is tested by the manufacturer according to procedures outlined in 40 CFR 60.5413b(d). For combustion devices where temperature is an indicator of destruction efficiency ( e.g., incinerators), the owner or operator must establish a temperature limit during the performance test and continuously monitor the temperature after the performance test. Owners and operators using catalytic vapor incinerators must establish a limit on the temperature at the inlet of the catalyst bed and the temperature differential across the catalyst bed during the performance test and continuously monitor these temperatures after the performance test. For all other enclosed combustion devices and flares, the owner and operator must maintain the net heating value (NHV) of the gas sent to the device above a minimum amount if the combustion device is pressure-assisted or uses no assist gas. If an owner or operator uses a steam-assisted enclosed combustion device, the owner or operator must maintain the combustion zone NHV above a minimum level. If the owner or operator uses an air-assisted enclosed combustion device, the owner or operator must maintain the NHV dilution parameter above a minimum level. The combustion zone NHV and NHV dilution parameter terms account for the reduction in heating value caused by the introduction of air and/or steam. These terms ensure that the assist gas does not overwhelm the heating value provided by the vent gas to the point where proper combustion is no longer occurring.

All flares and all enclosed combustion devices, other than boilers and process heaters that introduce the vent stream with the primary fuel into the flame zone and catalytic incinerators, must operate above a minimum flow rate established by the manufacturer. Additionally, the flow rate to a flare must be maintained at a level that ensures compliance with the flare tip velocity limits in the 40 CFR part 60 General Provisions, and the flow rate to an enclosed combustion device must be below a maximum flow rate established during the performance test or by the manufacturer, if the initial performance test is performed by the manufacturer. Flares and enclosed combustion devices that use pressure-assisted tips to promote mixing at the burner tip are not subject to this maximum flow rate limit because these units are designed to operate at high flow rates.

All flares and all enclosed combustion devices must also operate with a continuous burning pilot flame and with no visible emissions, except for periods not to exceed a total of 1 minute during any 15-minute period. Compliance with the visible emissions requirement can be confirmed either through monthly testing using EPA Method 22 or through continuous use of a video surveillance camera. Additionally, during each fugitive emissions inspection conducted using an OGI camera, including those conducted in response to periodic screening events using alternative technologies, owners and operators must observe each enclosed combustion device and flare to determine if it is operating properly, ensuring that a flame is present and that there is no indication of uncontrolled emissions. During each fugitive emissions inspection conducted using AVO, owners and operators must observe each enclosed combustion device and flare to determine if it is operating properly, visually confirming that the pilot flame is lit and operating properly.

Owners and operators also have the option to request an alternative test method to demonstrate continuous 95.0 percent control of emissions. In this option, the owner or operator would demonstrate that the combustion device continuously achieves 95.0 percent combustion efficiency or that the combustion device continuously complies with the combustion zone NHV and NHV dilution parameter requirements. The alternative test method would be used in lieu of the other monitoring required for combustion device ( e.g., vent gas NHV, flow rate).

b. Recordkeeping and Reporting Requirements

Owners and operators are required to maintain records and report the results of all performance tests conducted on combustion control devices. Additionally, for each continuous parameter monitoring system (CPMS) that is used to demonstrate continuous compliance for a combustion control device, owners and operators must report the identity of the CPMS, the date of last calibration, and the date, duration, and cause of all deviations. Owners and operators must also record and report the date, duration, and cause of events where emissions bypassed the control device and any period when visible emissions exceeded 1 minute during a 15-minute period. For each visible emissions test following return to operation from a maintenance or repair activity, owners and operators must record and report the date of the visible emissions test, the length of the test in minutes, and the number of minutes for which visible emissions were present.

If an owner or operator conducts a demonstration to prove that the NHV of the inlet gas to an enclosed combustion device or flare is consistently above the minimum required NHV, the owner or operator must record and report the results of the demonstration. Likewise, if an owner or operator conducts a demonstration that the maximum potential pressure of units manifolded to an enclosed combustion device or flare cannot cause the maximum inlet flow rate or the flare tip velocity limit to be exceeded, the owner or operator must record and report the results of the demonstration.

In addition to the information that must be reported, owners and operators must keep records of continuous compliance with the monitoring requirements, including indications that the pilot flame is lit, CPMS limits, CPMS hourly and average values, and results of visible emissions observations or surveillance camera feed. Owners and operators are also required to keep records of CPMS checks and audits, maintenance activities and repairs for each control device failing a visible emissions test, and the manufacturer's written operating instructions, procedures, and maintenance schedule to ensure good air pollution control practices for minimizing emissions. If an owner or operator uses a backpressure regulator valve to control the minimum flow rate to the combustion device, the owner or operator must keep records of the engineering evaluation and manufacturer specifications used to identify the set point and annual confirmation that the backpressure regulator valve set point is set correctly and that the valve fully closes when not in open position.

2. EG OOOOc

a. Compliance Assurance Requirements

The compliance requirements for combustion control devices on designated facilities specified in EG OOOOc are almost identical to the requirements specified in the NSPS OOOOb final rule. The only difference between the requirements in NSPS OOOOb and EG OOOOc is that for enclosed combustion devices and flares that are air-assisted or steam-assisted, the owner and operator would be required to maintain the NHV of the gas sent to the device above a minimum amount instead of monitoring the combustion zone NHV and the NHV dilution parameter. See section XI.H.5 of this preamble for more information on monitoring steam-assisted and air-assisted enclosed combustion devices and flares.

b. Recordkeeping and Reporting Requirements

The EG OOOOc recordkeeping and reporting requirements for combustion control devices on designated facilities specified in EG OOOOc are the same as those specified in the NSPS OOOOb final rule.

I. Reciprocating Compressors

1. NSPS OOOOb

a. Affected Facility

The reciprocating compressor affected facility is each reciprocating compressor, which is a single reciprocating compressor. A reciprocating compressor located at a well site is not a reciprocating compressor affected facility under this subpart. A reciprocating compressor located at a centralized production facility is a reciprocating compressor affected facility under this subpart.

b. Final Standards

The NSPS OOOOb standard of performance for reciprocating compressor affected facilities is a performance-based emissions standard of 2 scfm (in operating or standby pressurized mode) per cylinder. The volumetric flow rate of 2 scfm is an action level that, if exceeded, triggers the action of repairing or replacing the rod packing and is not a numeric limit. The volumetric flow rate measurement from each reciprocating rod packing must be maintained to be less than or equal to a flow rate of 2 scfm (in operating or standby pressurized mode) per cylinder. An owner or operator is required to repair or replace the rod packing and to conduct other necessary repair and maintenance in order to ensure the emission rate is maintained at or below 2 scfm (in operating or standby pressurized mode) per cylinder. Owners and operators must conduct volumetric flow rate measurements from each reciprocating compressor rod packing using the screening and monitoring methods specified in 40 CFR 60.5386b.

The EPA is requiring that the first and subsequent volumetric flow rate measurements from a reciprocating compressor affected facility be conducted on or before 8,760 hours of operation after the effective date of the final rule, on or before 8,760 hours of operation after the previous flow rate measurement, or on or before 8,760 hours of operation after the date of the most recent compressor rod packing replacement, whichever is later. Preventative maintenance or other corrective actions ( e.g., repair or replacement of rod packing) may be necessary in addition to monitoring every 8,760 hours of operation for owners or operators to ensure compliance (consistent with the general duty clause 40 CFR 60.5470b(b)) with the required flow rate of 2 scfm (in operating or standby pressurized mode) or less per cylinder). As an alternative to conducting required volumetric flow rate measurements, the final rule also allows an owner or operator the option to comply by replacing the rod packing on or before 8,760 hours of operation after the effective date of the final rule, on or before 8,760 hours of operation after the previous flow rate measurement, or on or before 8,760 hours of operation after the date of the most recent compressor rod packing replacement, whichever is later.

In the final rule, repair or replacement of the rod packing is required when the volumetric emission measurement of the reciprocating compressor rod packing has a flow rate greater than 2 scfm (in operating or standby pressurized mode) per cylinder or a combined rod packing flow rate greater than the number of compressor cylinders multiplied by 2 scfm. An owner or operator must repair or replace the reciprocating compressor rod packing within 90 calendar days from the date of the volumetric emissions measurement.

The final rule allows for a delay of repair if the repair or replacement would require a vent blowdown, or it would otherwise be infeasible or unsafe, until the next process unit shutdown. Specifically, if the repair or replacement is technically infeasible, would require a vent blowdown, a process unit or facility requires shutdown, parts or materials are unavailable, or it would be unsafe to repair during operation of the unit, the repair can be delayed but must be completed during the next scheduled process unit or facility shutdown for maintenance, after a scheduled vent blowdown, or within 2 years, whichever is earliest. In addition, if the repair requires replacement of the compressor rod packing or a part, but the necessary replacement rod packing or part cannot be acquired and installed within the repair timelines specified due to supplies being unavailable (where previously sufficiently-stocked), a delay of repair is allowed. However, in order to qualify for a delay of repair, the required rod packing or part replacement must be ordered no later than 10 calendar days after the reciprocating compressor is added to the delay-of-repair list due to parts unavailability.

Owner or operators must conduct volumetric flow rate measurements from each reciprocating compressor vent within 15 days after the repair to document that the rate has been reduced to less than the applicable flow rate per cylinder. If the individual cylinders are manifolded to a single open-ended vent line, the volumetric flow rate must be reduced to less than the sum of the individual cylinders multiplied by the applicable required flow rate per cylinder.

For the EPA's rationale for prescribing a work practice standard over a numeric standard, see section XI.I.1 of this preamble.

c. Routing Emissions From the Rod Packing to a Process or to a Control Device That Reduces Emissions by 95 Percent

Alternatively, an owner or operator may choose to comply with NSPS OOOOb by routing emissions from the rod packing via a CVS to a process or to a control device achieving 95 percent control. These options achieve emissions reductions greater than or equal to the 2 scfm performance-based emissions standard per cylinder. An owner or operator must ensure that the CVS is designed to capture and route all gases, vapors, and fumes to a process (40 CFR 60.5411b(a) and (c)).

An owner or operator complying with the alternative option to route to a process is required to design and operate the CVS with no identifiable emissions and would be subject to bypass requirements (as applicable). Initial, monthly, and annual inspections (using OGI, EPA Method 21, or AVO (for monthly inspections only)) are required to check for defects and identifiable emissions.

An owner or operator complying with the alternative option to route to a control device is required to design and operate the CVS with no identifiable emissions and would be subject to bypass requirements (as applicable). Initial, monthly, and annual inspections (using OGI, EPA Method 21, or AVO (for monthly inspections only)) of the CVS are required to check for defects and identifiable emissions. Control devices are required to meet the conditions specified in 40 CFR 60.5412b of the final rule.

d. Recordkeeping and Reporting Requirements

Owners or operators complying with the performance-based emissions standard must track and report in their annual report the cumulative number of hours of operation of each reciprocating compressor since startup, since the previous screening/volumetric flow rate emissions measurement, or since the previous reciprocating compressor repair/replacement of rod packing, as applicable. Their annual report must also include a description of the method used and the results of the volumetric flow rate measurement or emissions screening, as applicable. Lastly, owners or operators must maintain records and report each measurement that exceeds the 2 scfm performance-based emissions standard per cylinder standard during the reporting period, and the date and time the reciprocating compressor was repaired or packing replaced to meet the 2 scfm performance-based emissions standard. In the case of delay of repair due to parts unavailability, operators must document the date the reciprocating compressor was added to the delay-of-repair list, the date the required rod packing or part was ordered, the anticipated delivery date, and the actual delivery date; and the annual report needs to provide the reason for the needed delay and the date of anticipated repair or replacement.

For a reciprocating compressor affected facility complying by routing emissions from the rod packing to a process through a CVS, an owner or operator is required to maintain records and report each reciprocating compressor that was constructed, modified, or reconstructed during the reporting period that is complying by using this option. Owners or operators must maintain records and report each deviation from the performance-based emissions standard that occurred during the reporting period, the date and time the deviation began, duration of the deviation and a description of the deviation. Additionally, they would be required to report (in the annual report) the dates of each cover and CVS inspection, whether emissions are identified, and the date of repair or the date of anticipated repair if repair is delayed. Where bypass requirements apply, the date and time of each bypass alarm or each instance the key is checked out would also be included in the annual report.

For a reciprocating compressor affected facility complying by routing emissions from the rod packing to a control device through a CVS, an owner or operator is required to maintain records and report each reciprocating compressor that was constructed, modified, or reconstructed during the reporting period that is complying by using this option. In instances where a deviation from the standard has occurred during the reporting period, an owner or operator would be required to provide information on the date and time the deviation began, the duration of the deviation, and a description of the deviation. Additionally, they would be required to report (in the annual report) the dates of each cover and CVS inspection, whether emissions are identified, and the date of repair or the date of anticipated repair if repair is delayed. Where bypass requirements apply, the date and time of each bypass alarm or each instance the key is checked out would also be included in the annual report. For the reports and records that demonstrate proper design and operation of the control device that must be maintained, see sections X.H.1 and X.H.2 of this preamble.

2. EG OOOOc

a. Designated Facility

The reciprocating compressor designated facility is each reciprocating compressor, which is a single reciprocating compressor. A reciprocating compressor located at a well site is not a reciprocating compressor designated facility under this subpart. A reciprocating compressor located at a centralized production facility is a reciprocating compressor designated facility under this subpart.

b. Final Presumptive Standards

The presumptive standards for reciprocating compressor designated facilities are the same performance-based emissions work practice standard, or alternative routing emissions from the rod packing to a process or control device options as required in the NSPS OOOOb final rule. The final designated facility recordkeeping and reporting requirements specified in the final EG OOOOc rule are also the same as specified in the NSPS OOOOb final rule.

J. Storage Vessels

1. NSPS OOOOb

a. Affected Facility

A storage vessel affected facility subject to the final standards is defined as a tank battery that has the potential for VOC emissions equal to or greater than 6 tpy or methane emissions equal to or greater than 20 tpy is. A storage vessel is a tank or other vessel that contains an accumulation of crude oil, condensate, intermediate hydrocarbon liquids, or produced water, and that is constructed primarily of nonearthen materials. A tank battery is a group of all storage vessels that are manifolded together for liquid transfer. For purposes of this rule, a tank battery may consist of a single storage vessel if only one storage vessel is present.

b. Final Standards

Storage vessel affected facilities must reduce emissions of VOC and methane by 95 percent. The standard reflects the degree of emission limitation achievable through application of a combustion control device or VRU, which we have identified as the BSER for storage vessel affected facilities. See rationale for the BSER at section XII.B.1.e of the November 2021 Proposal and Chapter 6 of the of the November 2021 TSD which is unchanged in this final rule. For storage vessel affected facilities not at a well site or centralized production site and without potential for flashing emissions, owners and operators may choose to comply by using an internal or external floating roof to reduce emissions in accordance with 40 CFR part 60, subpart Kb (NSPS for Volatile Organic Liquid Storage Vessels). The rule allows removal of a control device from a storage vessel affected facility if the owner or operator maintains the uncontrolled actual VOC emissions at less than 4 tpy and the actual methane emissions at less than 14 tpy as determined monthly for 12 consecutive months.

c. Cover and Closed Vent System Requirements—Control Device Requirements

Storage vessel affected facilities which use a control device to reduce emissions must equip each storage vessel in the tank battery with a cover and must equip the tank battery with one or more closed vent systems which route all emissions to a process or one or more control devices. Flares and other control devices must conduct monitoring, recordkeeping, and reporting to ensure that the control device is continuously achieving the required 95 percent reduction. More information on the flare and other control device monitoring and compliance provisions is provided in section X.H of this preamble and information regarding covers and closed vent systems may be found in section X.K of this preamble.

d. Modification and Reconstruction

The EPA finalizes as proposed the definition of modification to include specific physical changes that will trigger the modification requirements ( i.e., adding an additional storage vessel, replacing existing storage vessel(s) that result in an increased capacity of the tank battery, receiving additional throughput from production well(s)) at tank batteries at well sites or centralized production facilities, or receiving additional fluids which cumulatively exceed the throughput used in the most recent determination of the potential for VOC or methane emissions not located at a well site or centralized production facility, including each tank battery at compressors stations or onshore natural gas processing plants that also result in exceeding the applicability threshold for either VOC or methane). The EPA defines reconstruction to mean at least half of the storage vessels are replaced in the existing tank battery that consists of more than one storage vessel, or the provisions of 40 CFR 60.15 are met for the existing tank battery and the resulting emissions exceed the applicability threshold for either VOC or methane.

e. Legally and Practicably Enforceable (LPE) Limitations

In this action, the EPA is finalizing the proposed criteria that must be met for a permit limit or other requirement to qualify as a legally and practicably enforceable limit for purposes of determining whether a tank battery is an affected facility or designated facility under NSPS OOOOb. A legally and practicably enforceable limit must include a quantitative production limit and quantitative operational limit(s) for the equipment, or quantitative operational limits for the equipment; an averaging time period for the production limit, if a production-based limit is used, that is equal to or less than 30 days; established parametric limits for the production and/or operational limit(s), and where a control device is used to achieve an operational limit, an initial compliance demonstration ( i.e., performance test) for the control device that establishes the parametric limits; ongoing monitoring of the parametric limits that demonstrates continuous compliance with the production and/or operational limit(s); recordkeeping by the owner or operator that demonstrates continuous compliance with the limit(s) in; and periodic reporting that demonstrates continuous compliance.

f. Recordkeeping and Reporting Requirements

In each annual report, owners and operators are required to identify each storage vessel affected facility that was constructed, modified, or reconstructed during the reporting period and must document the emission rates of both VOC and methane individually. The annual report must include deviations that occurred during the reporting period and information for control devices tested by the manufacturer or the date and results of the control device performance test for control devices not tested by the manufacturer. The report also must include the results of inspections of covers and CVS and the identification of storage vessel affected facilities (or portion of storage vessel affected facility) removed from service or returned to service. For storage vessel affected facilities which comply with the uncontrolled 4 tpy VOC limit or 14 tpy methane limit, the report must include changes which resulted in the source no longer complying with those limits and the dates that the source began to comply with the 95 percent reduction standard. The annual report must also include information on control devices used to achieve the 95 percent reduction standard. See section X.H of this preamble for more information related to reporting and recordkeeping for control devices.

Required records include documentation of the methane and VOC emissions determination and methodology, records of deviations and duration, records for the number of consecutive days a skid-mounted or permanently mobile-mounted storage vessel is on the site, the latitude and longitude coordinates of each storage vessel affected facility, dates that each storage vessel affected facility (or portion of storage vessel affected facility) is removed from service or returned to service, and records associated with control devices. For storage vessel affected facilities which comply with the uncontrolled 4 tpy VOC or 14 tpy methane limit, owners and operators must keep records of the monthly methane and VOC determination and methodology, records of changes which resulted in the source no longer complying with those limits, and the dates that the source began to comply with the 95 percent reduction standard. All associated records that demonstrate proper design and operation of the CVS, cover and control device also must be maintained (see section X.K and X.H of this preamble).

2. EG OOOOc

a. Designated Facility

A storage vessel is a tank or other vessel that contains an accumulation of crude oil, condensate, intermediate hydrocarbon liquids, or produced water, and that is constructed primarily of nonearthen materials. A tank battery is a group of all storage vessels that are manifolded together for liquid transfer. For purposes of EG OOOOc, a tank battery may consist of a single storage vessel if only one storage vessel is present. Each tank battery that has the potential for methane emissions greater than or equal to 20 tpy is a storage vessel designated facility.

b. Final Presumptive Standards

The presumptive methane standards in EG OOOOc for storage vessel designated facilities are the same emissions standards as those specified for methane for storage vessel affected facilities in the NSPS OOOOb final rule. Specifically, the presumptive standard is to reduce methane emissions by 95 percent. It reflects the degree of emission reduction through application of a combustion control device or VRU, which we have identified as the BSER for storage vessel designated facilities. See rationale for the BSER at section XII.B.2. of the November 2021 Proposal and Chapter 6 of the of the November 2021 TSD which is unchanged in this final rule. For storage vessel designated facilities not at a well site or centralized production site and without potential for flashing emissions, owners and operators could choose to comply by using an internal or external floating roof to reduce emissions in accordance with 40 CFR part 60, subpart Kb (NSPS for Volatile Organic Liquid Storage Vessels). In addition, the presumptive standards would allow removal of a control device from a storage vessel affected facility if the owner or operator maintains the uncontrolled actual VOC emissions at less than 4 tpy and the actual methane emissions at less than 14 tpy as determined monthly for 12 consecutive months. The designated facility presumptive recordkeeping and reporting requirements in the final EG OOOOc rule are also the same as those specified in the NSPS OOOOb final rule. Please see a summary of these requirements above in section X.J.1.f.

c. LPE Limitations

The EPA is finalizing the proposed criteria that must be met a permit limit or other requirement to qualify as a legally and practicably enforceable limits for purposes of determining whether a tank battery is designated facility under EG OOOOc. A legally and practicably enforceable limit must include a quantitative production limit and quantitative operational limit(s) for the equipment, or quantitative operational limits for the equipment; an averaging time period for the production limit, if a production-based limit is used, that is equal to or less than 30 days; established parametric limits for the production and/or operational limit(s), and where a control device is used to achieve an operational limit, an initial compliance demonstration ( i.e., performance test) for the control device that establishes the parametric limits; ongoing monitoring of the parametric limits that demonstrates continuous compliance with the production and/or operational limit(s); recordkeeping by the owner or operator that demonstrates continuous compliance with the limit(s) in; and periodic reporting that demonstrates continuous compliance. These criteria are the same as the LPE criteria for purposes of determining tank battery affected facility status finalized in NSPS OOOOb as outlined in X.J.1.e.

K. Covers and Closed Vent Systems

1. NSPS OOOOb

a. Compliance Assurance Requirements

This section of the preamble presents a summary of the final compliance assurance requirements for CVS and covers. As noted in section IV.K of the December 2022 Supplemental Proposal, the EPA proposed several changes to the compliance assurance requirements for CVS and covers between the November 2021 Proposal and the December 2022 Supplemental Proposal. First, the EPA proposed to align the design and operational requirements for CVS, regardless of which affected or designated facility is connected to the CVS and regardless of whether the emissions are being routed to a process or a control device. Second, the EPA proposed to allow the use of advanced methane detection technologies to demonstrate continuous compliance for CVS and covers. The use of advanced methane detection technologies to demonstrate continuous compliance for CVS and covers is discussed in section X.B of this preamble. Lastly the EPA proposed to change the emissions limit for covers and CVS from no detectable emissions (NDE) to no identifiable emissions (NIE). The EPA clarified that the proposed change was not intended to change the stringency of the standard, but to reflect the change in monitoring methods used for demonstrating compliance with the standard. NDE is a term closely linked with EPA Method 21; because the EPA proposed to allow owners and operators to demonstrate compliance with the emissions limit for covers and CVS using OGI and AVO in addition to EPA Method 21, the EPA proposed to change the terminology used in the standard from NDE to NIE. Further discussion on the NIE standard is provided below and in section XI.K.1 of this preamble. The final requirements for covers and CVS summarized below reflect the requirements that were proposed in the December 2022 Supplemental Proposal.

As in NSPS OOOO and OOOOa, NSPS OOOOb contains requirements for CVS and covers to ensure compliance with the standards for centrifugal compressor, reciprocating compressor, and storage vessel affected facilities. CVS route emissions from well ( i.e., oil wells when routing associated gas to a control device), centrifugal compressor, reciprocating compressor, process controllers, pumps, storage vessels and process unit affected facilities to a control device or to a process. Each CVS must be designed and operated to capture and route all gases, vapors, and fumes to a process or to a control device and comply with an emissions limit of NIE. Covers must form a continuous impermeable barrier over the entire surface area of the liquid in the storage vessel, over the centrifugal compressor wet seal fluid degassing system, or over the reciprocating compressor rod packing emissions collection system. Each cover opening shall be secured in a closed, sealed position ( e.g., covered by a gasketed lid or cap) whenever material is in the unit on which the cover is installed, except during those times when it is necessary to use an opening, such as to inspect equipment or to remove material from the equipment.

Initial and continuous compliance of the NIE standard would be demonstrated through OGI or EPA Method 21 monitoring and AVO inspections conducted at the same frequency as the fugitive emissions monitoring for the type of site where the cover and CVS are located. Alternatively, an owner or operator could demonstrate ongoing compliance with the NIE standard for covers and CVS using the periodic screening or continuous monitoring requirements for advanced methane detection technologies in 40 CFR 60.5398b, as described in section X.B of this preamble. Where AVO inspections are required, the CVS and cover is determined to operate with NIE if no emissions are detected by AVO means. Where OGI monitoring is conducted, the CVS and cover is determined to operate with NIE if no emissions are imaged by the OGI camera. Where EPA Method 21 monitoring is conducted, the CVS and cover is determined to operate with NIE if the readings obtained using EPA Method 21 are less than 500 parts per million by volume (ppmv) above background. Emissions detected by AVO, OGI, or EPA Method 21 constitute a deviation of the NIE standard until a subsequent inspection determines that the CVS and cover operates with NIE. Where monitoring is conducted using advanced methane detection technologies, covers and CVS are determined to operate with NIE if no emissions are detected by the periodic screening survey or, where continuous monitoring is conducted, the site remains under the action levels. If emissions are detected from the site during a periodic screening survey or the site exceeds an action level, the cover and CVS are still determined to operate with NIE unless a follow-up inspection with EPA Method 21, OGI, or AVO indicates that the cover and CVS do not operate with NIE.

Each CVS must be inspected to ensure that the CVS operates with NIE initially within 30 calendar days after startup of the affected facility routing emissions through the CVS and periodically. Specifically, for the well sites and centralized production facilities where a CVS is present, quarterly OGI or EPA Method 21 and bimonthly AVO would be required; for compressor stations, quarterly OGI or EPA Method 21 and monthly AVO would be required. For CVS and covers located at onshore natural gas processing plants, AVO inspections are required annually and instrument monitoring for NIE must be conducted either bimonthly with OGI following the procedures in appendix K or quarterly in accordance with EPA Method 21. For CVS joints, seams, and connections that are permanently or semi-permanently sealed, owners and operators are not required to conduct periodic instrument monitoring with OGI or EPA Method 21, but the owner or operator must still conduct initial instrument monitoring and periodic AVO monitoring. Additionally, annual visual inspections must be conducted for all CVS to check for defects, such as cracks, holes, or gaps.

If the CVS is equipped with a bypass, the bypass must include a flow monitor and sound an alarm to alert personnel or send a notification via remote alarm to the nearest field office that a bypass is being diverted to the atmosphere, or it must be equipped with a car-seal or lock-and-key configuration to ensure the valve remains in a non-diverting position. To ensure proper design, an assessment of the closed vent system must be conducted and certified by a qualified professional engineer or in-house engineer.

Any emissions or defects detected during an inspection of a cover or CVS is subject to repair, with a first attempt at repair within 5 days after detecting the emissions or defect and final repair within 30 days after detecting the emissions or defect. While awaiting final repair, covers must have a gasket-compatible grease applied to improve the seal. Delay of repair is allowed where the repair is infeasible without a shutdown, or it is determined that immediate repair would result in emissions greater than delaying repair. In all instances, repairs must be completed by the end of the next shutdown. Owner and operators may designate parts of the CVS as unsafe to inspect and difficult to inspect but must have a written plan of the inspection of this equipment. Equipment that is unsafe to inspect would expose inspecting personnel to an imminent potential danger; this equipment must be inspected as frequently as practicable, during safe to inspect times. Equipment that is difficult to inspect would require elevating inspecting personnel more than 2 meters above a support surface; this equipment must be inspected at least once every 5 years.

b. Recordkeeping and Reporting Requirements

The CVS certification must be submitted in the annual report in the reporting year in which the certification is signed. In each annual report, the owner or operator must report the date of each cover and CVS inspection, all defects or emissions identified during the inspections, and the date of repair or anticipated repair if the repair is delayed for each defect or emission. Owners and operators must also report the date and time of each bypass or alarm or each instance where the key is checked out. Records of CVS and cover inspections, CVS bypass monitoring, and CVS design and certifications must be maintained. The CVS certification must be submitted in the initial annual report.

Records for CVS and covers include records of inspections, CVS bypass monitoring, and CVS design and certifications. For each CVS or cover inspection, owners and operators must keep records of the date of the inspection, the method of inspection ( i.e., visual, AVO, OGI, or EPA Method 21), and all defects and emissions found. For each defect or emission found, the owner or operator must record the location, a description of the defect, the maximum concentration reading if EPA Method 21 is used, the date of detection, the date of each attempt to repair the defect or emission, the corrective action taken to repair the defect or emission, and the date of final repair of the defect or emission. If a repair is delayed, the owner or operator must record the reason for delay and the anticipated date of repair. Owners and operators must also keep records of unsafe and difficult to inspect portions of the CVS, including the written inspection plan. For each CVS bypass, owners and operators must keep records of readings from the flow indicator and the date and time of each instance the alarm is sounded, inspections of the seal or closure mechanism, and dates and times of each instance the key is checked out.

2. EG OOOOc

a. Compliance Assurance Requirements

The model rule in EG OOOOc includes the same covers and CVS requirements as those in NSPS OOOOb to assure that emissions from designated facilities, such as wells ( i.e., oil wells when routing associated gas to a control device), centrifugal compressors, reciprocating compressors, process controllers, pumps, and process unit, are captured and routed to a control device or process when such control device or process are being used to meet the presumptive standards for the designated facilities.

b. Recordkeeping and Reporting Requirements

The recordkeeping and reporting requirements for EG OOOOc are the same as those for NSPS OOOOb.

L. Equipment Leaks at Natural Gas Processing Plants

1. NSPS OOOOb

a. Affected Facility

Each process unit equipment affected facility, which is the group of all equipment within a process unit at an onshore natural gas processing plant, is an affected facility. Equipment, as used in the standards and requirements of this subpart relative to the process unit equipment affected facility at onshore natural gas processing plants, means each pump, pressure relief device, open-ended valve or line, valve, and flange or other connector that has the potential to emit methane or VOC and any device or system required by those same standards and requirements of this subpart. Process unit means components assembled for the extraction of natural gas liquids from field gas, the fractionation of the liquids into natural gas products, or other operations associated with the processing of natural gas products. A process unit can operate independently if supplied with sufficient feed or raw materials and sufficient storage facilities for the products.

b. Final Standards

The NSPS OOOOb final standards apply to the “process unit equipment” affected facility and require that, for each piece of equipment that has the PTE methane or VOC, owners and operators conduct bimonthly ( i.e., once every other month) OGI monitoring in accordance with 40 CFR part 60, appendix K to detect equipment leaks from pumps in light liquid service, pressure relief devices in gas/vapor service, valves in gas/vapor or light liquid service, connectors in gas/vapor or light liquid service, and CVS. As an alternative to the bimonthly OGI monitoring, EPA Method 21 may be used to detect leaks from the same equipment at frequencies specific to the process unit equipment type ( e.g., monthly for pumps, quarterly for valves). Open-ended valves and lines, pumps, valves and connectors in heavy liquid service and pressure relief devices in light liquid or heavy liquid service must be monitored using AVO. The final rule requires that when a leak is detected it must be repaired. Valves must be repaired by replacing the leaking valve with a low emission (low-E) valve, where technically feasible. The final rule also includes requirements that the leaking equipment must be tagged for identification and a first attempt at repair for all identified leaks must be commenced within 5 days after detection, with final repair completed within 15 days after detection (unless the delay-of-repair provisions are applicable). Delay of repair would be allowed where it is technically infeasible to complete repairs within 15 days without a process unit shutdown. See rationale for the BSER at section XII.H.1.c. of the November 2021 Proposal which is unchanged in this final rule.

In addition to the monitoring and repair requirements summarized previously, the final rule includes requirements for specific types of equipment. Each open-ended valve or line must be equipped with a closure device ( i.e., cap, blind flange, plug, or a second valve) that seals the open end at all times except during operations which require process fluid flow through the open-ended valve or line. CVS used to comply with the standards for process unit equipment must be monitored bimonthly using OGI (or quarterly using EPA Method 21 if this alternative is used). Control devices used to comply with the equipment leak provisions must comply with the requirements described in section X.H of this preamble. Pressure relief devices must be monitored within 5 days after a pressure release to ensure the device has reseated after a pressure release. The final rule allows exceptions to the 5-day post-pressure release monitoring requirement for pressure relief devices that are located in a non-fractionating plant where the non-fractionating plant is monitored only by non-plant personnel that are not onsite. The exception allows the pressure relief device to be monitored after a pressure release the next time non-plant monitoring personnel are onsite, but in no event can the monitoring be delayed beyond 30 calendar days after a pressure release. Pressure relief devices that are routed to a process, fuel gas system, or control device are not required to be monitored following a release because the emissions from the release are controlled. The rule also provides exceptions to the GHG and VOC standards for process unit equipment affected facilities for certain types of equipment at a non-fractionating plant that does not have the design capacity to process 283,200 standard cubic meters per day (scmd) (10 million scf per day) or more of field gas and for equipment within a process unit at the Alaskan North Slope.

NSPS OOOOb reporting is required semiannually for process unit equipment affected facilities, which differs from the annual reporting for other affected facilities in NSPS OOOOb. In the initial semiannual report, the owner or operator must identify: each process unit associated with the process unit equipment affected facility; the number of each type of equipment subject to the monitoring requirements; for each month of the reporting period, the number of leaking equipment for which leaks were identified, the number of leaking equipment for which leaks were not repaired, and the facts that explain each delay of repair; and dates of process unit shutdowns. In subsequent semiannual reports, owners and operators must report the name of each process unit associated with the process unit equipment affected facility; any changes to the process unit identification or the number or type of equipment subject to the monitoring requirements; for each month of the reporting period, the number of leaking equipment for which leaks were identified, the number of leaking equipment for which leaks were not repaired, and the facts that explain each delay of repair; and dates of process unit shutdowns.

Required records in the final rule include inspection records consisting of equipment identification, date and start and end times of the monitoring inspection, inspector name, leak determination method, monitoring instrument identification, type of equipment monitored, process unit identification, appendix K records (where applicable), EPA Method 21 instrument readings and calibration results (where applicable) and, for visual inspections, the date, name of inspector and result of inspection. For each leak detected, the final rule requires recording of the instrument and operator identification (or record of AVO method, where applicable), the date the leak was detected, the date and repair method applied for first attempts at repair, indication of whether the leak is still detected, and the date of successful repair, which includes results of a resurvey to verify repair. For each delay of repair, the final rule requires that the equipment is identified as “repair delayed” along with the reason for the delay, the signature of the certifying official, and the dates of process unit shutdowns which occurred while the equipment is unrepaired. Additionally, the final rule requires records of equipment designated for NDE; the identification of valves, pumps, and connectors that are designated as unsafe-to-monitor, an explanation stating why it is unsafe-to-monitor, and the plan for monitoring that equipment; a list of identification numbers for valves that are designated as difficult-to-monitor, an explanation stating why it is difficult-to-monitor, and the schedule for monitoring each valve; a list of identification numbers for equipment that is in vacuum service and a list of identification numbers for equipment designated as having the PTE methane or VOC less than 300 hr/yr.

Finally, for CVS and control devices used to control emissions from process unit equipment affected facilities, the reports and records that demonstrate proper design and operation of the control device also must be maintained (see section X.H. of this preamble).

With the exception of the requirements for low-E valves, where technically feasible, these standards are unchanged from section IV.L.1 of the December 2022 Supplemental Proposal. For each valve where a leak is detected, you must comply by repacking the existing valve with a low-E packing, replacing the existing valve with a low-E valve; or performing a drill and tap repair with a low-E injectable packing. An owner or operator is not required to utilize a low-E valve or low-E packing to replace or repack a valve if the owner or operator demonstrates that a low-E valve or low-E packing is not technically feasible. Low-E valve or low-E packing that is not suitable for its intended use is considered to be technically infeasible. Factors that may be considered in determining technical infeasibility include: retrofit requirements for installation ( e.g., re-piping or space limitation), commercial unavailability for valve type, or certain instrumentation assemblies.

2. EG OOOOc

a. Designated Facility

Each process unit equipment designated facility, which is the group of all equipment within a process unit at an onshore natural gas processing plant, is a designated facility. Equipment, as used in the standards and requirements of this subpart relative to the process unit equipment designated facility at onshore natural gas processing plants, means each pump, pressure relief device, open-ended valve or line, valve, and flange or other connector that has the potential to emit methane and any device or system required by those same standards and requirements of this subpart. Process unit means components assembled for the extraction of natural gas liquids from field gas, the fractionation of the liquids into natural gas products, or other operations associated with the processing of natural gas products. A process unit can operate independently if supplied with sufficient feed or raw materials and sufficient storage facilities for the products.

b. Final Standards

The EG OOOOc final methane presumptive standards for “process unit equipment” designated facilities are the same as finalized for NSPS OOOOb affected facilities. The Model Rule reporting and recordkeeping requirements are also the same as finalized for NSPS OOOOb affected facilities.

With the exception of low-E valves, these presumptive standards are unchanged from section IV.L.2 of the December 2022 Supplemental Proposal. See rationale for the BSER at section XII.B.2 of the November 2021 Proposal which is unchanged in this final rule.

M. Sweetening Units

1. Affected Facility

A sweetening unit refers to a process device that removes H₂ S and/or CO₂ from the sour natural gas stream— i.e., sweetening units convert H₂ S in acid gases ( i.e., H₂ S and CO₂) that are separated from natural gas by a sweetening process, like amine gas treatment, into elemental sulfur in the Claus process. Each sweetening unit that processes natural gas produced from either onshore or offshore wells is an affected facility as well as each sweetening unit that processes natural gas followed by a sulfur recovery unit.

2. Final Standards

Affected facilities with a sulfur production rate of at least 5 long tons per day (LT/D) must reduce SO₂ emissions by 99.9 percent. Compliance with the standard is determined based on an initial performance test and daily reduction efficiency measurements. During the performance test, the minimum required reduction efficiency of SO₂ emissions is determined for the sweetening unit. For affected facilities that have a design capacity less than 2 LT/D of H₂ S in the acid gas (expressed as sulfur), recordkeeping and reporting requirements are required. However, emissions control requirements are not required. Facilities that produce acid gas that is entirely reinjected into oil/gas-bearing strata or that is otherwise not released to the atmosphere are also not subject to emissions control requirements.

For affected facilities that use an oxidation control system, or a reduction control system followed by an incineration device, an owner or operator must (1) continually operate the oxidation/incineration device and (2) install, calibrate, maintain, and operate monitoring devices and continuous emission monitors. For affected facilities that use a reduction control system not followed by an incineration device, an owner or operator must install, calibrate, maintain, and operate a continuous monitoring system to measure the emission rate of reduced sulfur compounds.

Owners and operators of a sweetening unit device affected facility are required to submit notifications required under the NSPS General Provisions, initial and annual reports, and excess emissions reports (as applicable). Affected facilities are also required to retain records of the following:

(1) the applicable calculations and measurements,

(2) an analysis demonstrating that the facility's design capacity is less than 2 LT/D of H₂ S expressed as sulfur to document exemption from the control requirements (when applicable), and

(3) a record demonstrating that the facility's design capacity is less than 150 LT/D of H₂ S expressed as sulfur (if electing to comply with 40 CFR 60.5407b(e)).

This is unchanged from section IV.M of the December 2022 Supplemental Proposal.

N. Electronic Reporting

To increase the ease and efficiency of data submittal and data accessibility, the EPA is finalizing, as proposed, a requirement that owners and operators submit electronic copies of performance test reports, natural gas processing plant semiannual reports, annual reports, and notifications of well closure activities through the EPA's Central Data Exchange (CDX) using the Compliance and Emissions Data Reporting Interface (CEDRI). A description of the electronic data submission process is provided in the memorandum, Electronic Reporting Requirements for New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants (NESHAP) Rules, available in the docket for this action. The final rulemaking requires that performance test results be submitted in the format generated through the use of the ERT or an electronic file consistent with the xml schema on the ERT website. For natural gas processing plant semiannual reports and annual reports, the final rule requires that owners and operators use the appropriate spreadsheet template to submit information to CEDRI. The final version of the templates for these reports will be located on the CEDRI website. The final rulemaking requires that notifications of well closure activities be submitted as a portable document format (PDF) upload in CEDRI. The EPA is also finalizing, as proposed, these same requirements in EG OOOOc.

Furthermore, the EPA is finalizing in NSPS OOOOb and EG OOOOc, as proposed, provisions that allow owners and operators the ability to seek extensions for submitting electronic reports for circumstances beyond the control of the facility, i.e., for a possible outage in CDX or CEDRI or for a force majeure event, in the time just prior to a report's due date, as well as the process to assert such a claim.

O. Prevention of Significant Deterioration and Title V Permitting

The pollutants subject to regulation in this final rulemaking are VOC and GHGs (which are regulated in this rule in the form of methane limitations). As explained in section XV of this preamble, we are finalizing provisions to NSPS OOOOb and EG OOOOc, analogous to what was included in the 2016 NSPS OOOOa and other rules regulating GHGs from electric utility generating units, to address some of the potential implications this final rulemaking could have on the CAA Prevention of Significant Deterioration (PSD) preconstruction permit program and the CAA title V operating permit program.

XI. Significant Comments and Changes Since Supplemental Proposal for NSPS OOOOb and EG OOOOc

This section of the preamble presents in each subsection a summary of any changes since the December 2022 Supplemental Proposal for the topic being addressed in that subsection, as well as significant comments on that topic and the EPA's response thereto. For final NSPS standards and requirements and final EG presumptive standards and requirements that have not changed since the December 2022 Supplemental Proposal, the supporting rationales for the EPA's BSER determinations are not reiterated in this preamble. The rationale for these standards and requirements can be found in the preamble to the December 2022 Supplemental Proposal and in the TSD for the December 2022 Supplemental Proposal. The EPA's full response to comments on the November 2021 Proposal and December 2022 Supplemental Proposal, including any comments not discussed in this preamble, can be found in the EPA's RTC document for the final rule.

A. Fugitive Emissions From Well Sites, Centralized Production Facilities, and Compressor Stations

1. Fugitive emissions at Well Sites and Centralized Production Facilities

In section X.A.1 of this document, the final NSPS OOOOb and EG OOOOc requirements for fugitive emissions components at well sites and centralized production facilities are summarized. The BSER analysis for fugitive emissions components at well sites and centralized production facilities is unchanged from what was presented in the December 2022 Supplemental Proposal (see 87 FR 74729–39, section IV.A.1: Fugitive Emissions at Well Sites and Centralized Production Facilities). Significant comments were received on the December 2022 Supplemental Proposal on the following topics: (1) the definition of fugitive emissions component, (2) the EPA's assumption regarding the effectiveness of OGI and AVO, (3) the order of evaluating AVO in the BSER analysis, (4) subcategorization of well sites, and (5) miscellaneous other changes. For each of these topics, a summary of the proposed rule (where relevant), the comments, the EPA responses, and changes made in the final rule (if applicable), are discussed here. These comments and the EPA's responses to these comments generally apply to the standards proposed in both the NSPS OOOOb and EG OOOOc. The instances where the comment and/or response only applies to the NSPS OOOOb or EG OOOOc are noted. The EPA's full response to comments on the November 2021 Proposal and December 2022 Supplemental Proposal, including any comments not discussed in this preamble, can be found in the EPA's RTC document for the final rule. This section of this document presents a summary of significant comments received on fugitive emissions components affected or designated facilities located at well sites and centralized production facilities and the EPA's response to those comments, as well as changes the EPA has made to the well site fugitive emissions requirements of NSPS OOOOb and EG OOOOc since the December 2022 Supplemental Proposal.

a. Fugitive emissions component definition

Comment: Commenters suggested various revisions to the proposed definition of fugitive emissions components. A commenter asked that the EPA exclude yard piping from the definition because this inclusion would expand the definition in an unprecedented way. According to the commenter, cracks and holes in piping have never been considered fugitive components in any other rule for LDAR in any industry sector by the Agency. The commenter asserted that the EPA has not explained how leak detection should be conducted for yard piping, as compared to other fugitive emissions components where there are identifiable leak points (such as valve stems or flange interfaces) that are the target of monitoring. The commenter also noted that cracks and holes represent potential loss of containment and are already repaired and corrected per industry practice and code. Another commenter asked that the EPA exclude buried yard piping from the definition of fugitive emissions components because buried components are difficult or impossible to monitor.

Another commenter supported the EPA's inclusion of yard piping in the definition. This same commenter asked that the EPA also include certain equipment types like separators in the definition so monitoring of separator dump valves and components on all other equipment would clearly be required. The commenter noted that separator dump valves are a known source of large fugitive emissions events. In response to the November 2021 Proposal, the commenter had made a similar case for inclusion of separator dump valves in the definition in order to ensure that these components are monitored.

Response: In the final NSPS OOOOb and EG OOOOc rules, the EPA has retained yard piping in the definition of fugitive emissions components. A definition of yard piping was added for clarity. As discussed in the December 2022 Supplemental Proposal, pipes can experience cracks or holes, which can lead to fugitive emissions. The inclusion of yard piping in the definition of fugitive emissions components will help ensure that fugitive emissions from these sources do not go undetected during fugitive emissions monitoring and that issues found from the pipe itself leading to the fugitive emissions are addressed. If industry is already conducting checks for leaks as standard practice and code, this would further assist in ensuring that fugitive emissions are minimized. AVO and OGI can be used to detect fugitive emissions from cracks and other defects in yard piping by scanning along the length of the piping. However, the EPA acknowledges that EPA Method 21 does not include instructions for monitoring yard piping; therefore, the EPA is providing directions in this final rule on how to monitor yard piping while conducting an EPA Method 21 monitoring survey. Lastly, the EPA recognizes the difficulty of monitoring yard piping that is buried, as it may require disturbing the surface, which could inadvertently cause emissions; therefore, the final NSPS OOOOb and EG OOOOc rules only require monitoring of yard piping and associated fugitive components ( e.g., connectors) that are at or above ground level.

Regarding a commenter's request that the definition of fugitive emissions components explicitly include separators, the EPA agrees that, although the list of components in the definition is not exhaustive, it is worthwhile to eliminate any ambiguity as to whether separator dump valves are fugitive emissions components. The EPA is finalizing a definition of fugitive emissions components in NSPS OOOOb and EG OOOOc that specifically includes separator dump valves, thus clarifying that the separator dump valve is subject to monitoring by OGI, AVO, or other detection methods. In addition, because malfunctioning separator dump valves are a known source of large emissions (as the commenter noted) and because sometimes there is visual evidence of the malfunction, the EPA is requiring in the final rule that, during the regular AVO monitoring surveys (either quarterly or bimonthly depending on the site), a visual inspection must be conducted of all separator dump valves to ensure that they are free of debris and not stuck in an open position, and any dump valve not operating as designed must be repaired.

b. OGI and AVO Effectiveness

Comment: Some commenters claimed that the EPA's assumptions for OGI and AVO effectiveness in both NSPS OOOOb and EG OOOOc are overstated and need to be adjusted. Specifically, these commenters were concerned the upper bound assumption of the percentage of leaks that will be detected by either method should be adjusted to reflect that these methods will not find all leaks during a survey. These commenters suggested that not all leaks, even large ones, would be observed during the monitoring survey, so not all the leaks would be repaired.

One commenter specifically objected to the EPA's reliance on emissions information from the 2021 Rutherford, et al., study because the commenter believes the study “cherry-picks” data. This same commenter believes that the EPA ignores relevant information from the U.S. DOE marginal well study and urged the use of DOE emissions data in FEAST modeling to evaluate programs for low production and existing sites.

Conversely, one commenter asserted that the EPA's assumptions about the effectiveness of OGI are supported by recent data and FEAST modeling. One commenter believes that all inputs used by the EPA are reasonable, are appropriate, and ensure that advanced technologies deliver emissions reductions commensurate with OGI across diverse basins.

Other commenters expressed overall support of the use of FEAST modeling and recommended some adjustments. One commenter noted that intermittency of emissions should be represented in modeling. As it specifically relates to AVO, one commenter indicated that there is limited availability of information and studies on the effectiveness of AVO inspections for emissions with variable rates, intermittent emissions, emissions elevated above ground level, [varying] emission point aperture sizes, and emissions occurring in varying ambient conditions ( e.g., wind, rain, and other ambient equipment/process/compressor noise that may obstruct detection). The commenter recommended that the EPA perform or seek out studies of AVO effectiveness across this range of conditions before incorporating it into the FEAST model for calculation of emissions reductions for purposes of equivalency demonstration for alternative monitoring solutions. Another commenter noted that leak detection and repair data collected in Colorado show both different annual rates for leaks requiring repair as well as few leaks requiring repair as detected by AVO.

Response: As discussed in the December 2022 Supplemental Proposal preamble and noted by the commenters, the revised approach for estimating the fugitive emissions under different monitoring scenarios at well sites uses a FEAST modeling approach based on the presence of specific types of equipment at well sites. The modeling uses built-in emissions data from various emissions measurement campaigns which were supplemented with additional study data to provide an empirical emissions dataset for the model simulations. The EPA used the FEAST model to evaluate potential fugitive emissions monitoring and repair programs at well sites (87 FR 74725). The effectiveness of fugitive emissions monitoring and repair programs are simulated within the FEAST model based on the probability of detection (PoD) curves (or surfaces) for each monitoring method and frequency, which indicate the probability that a leak of a given size will be detected within a given survey. Survey times (frequencies) are accounted for as finite time periods. The model quantifies emissions occurring at a site over a period of time ( e.g., we used a 5-year simulation and evaluated the emissions in the fifth year of the simulation), accounting for simulated leak generation, identification, and repair rates. Emissions reductions are calculated by comparing the simulated fugitive emissions program against a baseline scenario where no program is implemented.

The emissions data used in the FEAST model included data from direct measurement campaigns. Despite some shortcomings of the data in studies analyzed in the Rutherford, et al., study, the study is useful because it analyzes and reconciles multiple sources of data and multiple methods of estimating emissions to arrive at a more robust and validated model of component-level emissions from well sites. The EPA chose to use the Rutherford, et al., study and the U.S. DOE marginal well study to help inform assumptions necessary to establish a baseline emissions scenario in the FEAST model because they represent credible compilations of relevant emissions data at the well site level. The set-up of the FEAST model was further validated by finding that the results generated by FEAST regarding the effectiveness of different OGI monitoring frequencies align well with other values reported in literature. The EPA found that the FEAST results align with the EPA's historical assumptions of 40, 60, and 80 percent, for annual, semiannual, and quarterly OGI monitoring, respectively, and these percent efficiencies compare well to those discussed in the TSD for the 2020 Technical Rule.

For the December 2022 Supplemental Proposal, the FEAST modeling conducted generally assumed a 100 percent probability of OGI camera operators' seeing all leaks above a certain size threshold. Following the December 2022 Supplemental Proposal, the EPA investigated the effect of lowering the probability of detection, based on public comments received asserting that not all leaks would necessarily be detected (and subsequently lower emissions reductions would be achieved). The EPA modeled ground-based surveys with maximum probability of detection of 70, 90, and 100 percent detection limits. A complete discussion of the EPA's assessment of the maximum probability of detection is presented in a memorandum available in the rulemaking docket. The results of this additional modeling suggest that lowering the maximum probability of detection would not appreciably change either the control effectiveness of various fugitive emissions monitoring and repair programs or the conclusion regarding the cost-effective monitoring programs. Therefore, the EPA maintains that the OGI percent reduction efficiencies obtained via the FEAST modeling that was conducted for the December 2022 Supplemental Proposal (see tables 11–13 of the December 2022 Supplemental Proposal (87 FR 74732–34), which align with previous assumptions and existing literature, are representative.

With respect to AVO effectiveness, the EPA did use an upper level of detection of 90 percent for AVO monitoring. The EPA acknowledges that the level of detection for AVO will be more variable than for OGI because leaks detected by olfactory methods (smell) will largely rely on other constituents present in the natural gas. However, the modeling runs when using AVO alone provided reasonable agreement with the emissions from oil and gas production sites that rely primarily on AVO inspections as reported in the U.S. DOE marginal well study data. Therefore, the EPA concluded that the modeling assumptions regarding the effectiveness of AVO monitoring were reasonable.

With respect to the recommendation to include intermittent emissions events in the FEAST model, the EPA has not done so for the following reasons. First, in order to model intermittent emissions events, assumptions would have to be made regarding the fraction of fugitive emissions that exhibit intermittent behavior and the typical duration of active emissions and of periods of low or zero emissions. Because the EPA has limited data from which to make these necessary assumptions, to include intermittent emissions events in the model would introduce great uncertainty to the model. Second, the EPA notes that intermittent emissions events are largely reported with respect to “super-emitters,” which the EPA is addressing through the Super Emitter Program established in this final rule. For the reasons stated, the EPA has not included intermittent emissions events in the model.

c. Order of AVO evaluation in the BSER

Comment: One commenter believes that the EPA should have developed its regulatory strategy by first evaluating AVO and determining its cost effectiveness; then, the EPA should have assessed the impact of adding OGI monitoring. The commenter believes that evaluating whether additional OGI monitoring is appropriate and at what frequency should have come after the evaluation of AVO inspection in the EPA's BSER analysis for NSPS OOOOb and EG OOOOc. According to the commenter, this is particularly relevant for multi-wellhead only well sites (where the proposed requirement was semiannual OGI and quarterly AVO) as the EPA acknowledged that large leaks from a wellhead could be detected with AVO. Commenters claimed that the EPA did not provide adequate justification as to why having two or more wellheads requires the use of OGI. Industry commenters believe that the NSPS OOOOb and EG OOOOc BSER for multi-wellhead only sites should be quarterly AVO inspections only (bimonthly AVO inspections only at most). Another commenter similarly expressed that using AVO inspections to find large fugitive emissions at single wellhead only sites is appropriate and should also apply to multi-wellhead only well sites. Quarterly AVO inspections are appropriate to detect fugitive emissions at multi-wellhead only well sites, according to the commenter. A commenter stated that wellhead only sites generally have fewer fugitive emissions components, and wellheads are constructed with thicker, higher-pressure-rated iron, causing flanges to be larger such that AVO inspections are able to reliably detect any leaks that may occur. The commenter believed quarterly AVO inspection of wellhead only sites would be an effective and economic means to monitor for leaks at wellhead only sites. Another commenter expressed support for AVO for these sites but did not support OGI, due to its cost and because the incremental benefit of using OGI on top of AVO would not meaningfully reduce emissions.

Response: The EPA disagrees with the comment that it should have first evaluated AVO and determined its cost effectiveness and then assessed whether to add OGI monitoring for multi-wellhead only well sites and well sites with major production and processing equipment. While OGI's superiority over AVO is clear, the EPA nevertheless offered a detailed explanation in the December 2022 Supplemental Proposal (87 FR 74727). As the EPA explained, AVO is a simple sensory method that can detect large releases such as emissions from open thief hatches; however, not all fugitive emissions components have large releases and, therefore, their emissions cannot always be detected by AVO. AVO's reliability also depends on other factors, including whether the background noise is sufficiently low to allow a person to hear leaks such as the hissing sound from a high-pressure leak, whether the gas is of a mixture that would allow detection by smell, or whether the leaks result in dripping or puddles that can be detected visually. In contrast, OGI can reliably detect fugitive emissions that AVO cannot. Therefore, in the November 2021 Proposal, the EPA proposed monitoring fugitive emissions using OGI at well sites with baseline emissions at or greater than 3 tpy and no monitoring for those with baseline emissions below that level; the EPA solicited comment on “simple AVO checks that could be performed in conjunction with the periodic OGI monitoring surveys to help identify potential large emission events” (86 FR 63197). In the December 2022 Supplemental Proposal, the EPA proposed four subcategories of well sites and monitoring regime for each subcategory based on numbers and types of equipment. For example, single wellhead only well sites have few pieces of simple equipment and therefore few fugitive emissions components, but they have been found to have large emissions that result from fugitive emissions components, such as an open valve on a well case casing; because the number of components is small and the large releases could be detected with AVO, OGI monitoring does not seem necessary at a single wellhead only well site. That is not the case with multi-wellhead only well sites, which are the focus of the comments summarized above. As the number of wellheads increases, so does the number of fugitive emissions components, including those associated with smaller emissions that are difficult to detect with AVO; however, OGI can detect fugitive emissions from those components in addition to the large releases. Accordingly, in the December 2022 Supplemental Proposal, the EPA proposed adding AVO monitoring to routine OGI monitoring requirements in order to identify large emissions that could occur in between scheduled OGI surveys at multi-wellhead only well sites and well sites with major production and processing equipment (see 87 FR 74722).

As discussed in the December 2022 Supplemental Proposal, multi-wellhead only well sites feature both large emission sources that can be identified with AVO as well as additional, generally smaller sources of emissions that are more challenging to identify using AVO. In order to capture both large and small emissions from multi-wellhead only well sites, the EPA proposed semiannual OGI monitoring and quarterly AVO surveys for NSPS OOOOb and EG OOOOc. The EPA agrees with commenters that periodic AVO surveys are less costly than OGI surveys. However, cost is not the only factor in determining the BSER, and other considerations, such as effectiveness at reducing emissions from both large and small releases, must be considered. As part of its BSER analysis for reducing fugitive emissions at well sites, the EPA analyzed the costs and emission reductions associated with various combinations of OGI and AVO monitoring options for the four categories of well sites. The EPA summarized its analysis for multi-wellhead only well sites in table 12 and explained how it evaluated the various options (see 87 FR 74733, table 12). The EPA found semiannual OGI and quarterly AVO to be cost-effective and therefore to be the BSER for multi-wellhead only well sites.

d. Subcategorization of Well Sites

Comment: Several commenters requested that the EPA consider maintaining an exemption for low production wells as it pertains to the NSPS OOOOb and EG OOOOc. These commenters noted that industry has consistently advocated for such an exemption in previous rulemakings. Commenters also asserted that exempting low production wells would provide meaningful reductions in compliance burden and cost for small businesses, with minimal potential impact. Commenters argued that the proposed monitoring requirements and schedule are excessive for these sites, provide little environmental benefit, and are prohibitive for small owners and operators and will result in the end of their operations. One commenter noted that the U.S. DOE marginal well study provides data showing that marginal well sites overwhelmingly have methane emissions below 3 tpy. One commenter urged the EPA to modify the rule to include a production rate threshold that would exempt wells making less than 6 boe per day. One commenter recommended that the EPA create an intermediate well site category that combines production throughput and components, opining that this would be a simpler approach that avoids inappropriate results. According to the commenter, under the current proposal, some low-producing sites would be classified as large sites and be subject to quarterly OGI monitoring with bimonthly AVO inspections. The commenter asserted that the data from the U.S. DOE marginal well study shows that this category of sites has lower total emissions than sites with larger production volumes and therefore should not be subject to monitoring requirements as stringent as those for larger-producing sites. The commenter proposed that intermediate well sites historically considered to be “low production” be permitted to utilize industry practices to identify leaks. The commenter asserted that the EPA's proposal places an economic burden on owners/operators of low production wells that is not justified or supported.

Response: Following the December 2022 Supplemental Proposal, the EPA received the underlying dataset for the U.S. DOE marginal well study, which was previously not available, and the EPA further evaluated the methane emissions data obtained during the field campaigns of the U.S. DOE marginal well study. Specifically, in response to comments that the EPA should have incorporated the DOE emissions dataset into the FEAST modeling because the baseline emissions estimated by the EPA were overstated and that lower baseline emissions should be used, the EPA added U.S. DOE marginal well study data to the previous FEAST model simulations to evaluate whether this was the case.

The EPA also evaluated how the leaks measured in the U.S. DOE marginal well study compared with the leaks measured in the other studies included in the FEAST model as used to support the supplemental proposal. The EPA determined that the U.S. DOE marginal well study data agrees well with the emissions data included in FEAST as modeled for the December 2022 Supplemental Proposal when comparing the different equipment component leak data used. The EPA also ran several individual monitoring options using the equipment component data from the December 2022 Supplemental Proposal, using the component data from the December 2022 Supplemental Proposal augmented with U.S. DOE marginal well study data, and also using only the U.S. DOE marginal well study data. The FEAST model was run using these three sets of equipment component leak input data for multi-wellhead only well sites. The results demonstrated that varying the specific equipment component leak input data had minimal impact on the model results, and the FEAST model simulation results did not vary significantly when U.S. DOE marginal well study data was included. The full results of the additional FEAST modeling the EPA performed following the December 2022 Supplemental Proposal are presented in a memorandum available in the rulemaking docket. In conclusion, the addition of U.S. DOE marginal well study data did not show results that are significantly different than what the EPA presented in the December 2022 Supplemental Proposal.

Moreover, the U.S. DOE marginal well study concludes that the frequency and magnitude of emissions from well sites are more strongly correlated with equipment counts than with production rates. See the EPA's response in section XII.A for additional details and data.

The EPA therefore does not have compelling information that suggests low production levels at well sites should provide the basis for adding a new subcategory to the fugitive emissions requirements.

Many factors can affect the profitability of marginal wells and the decision to shut in and plug a well, making it difficult to determine the full impact of regulation on the financial status of marginal well owners, as discussed in chapter 6 of the final rule TSD. While the EPA does not have data on the distribution of ownership based on firm size, there are small owners and operators who own marginal oil and natural gas wells. The EPA remains mindful of how the fugitive emissions monitoring requirements will affect small entities and describes steps taken to include regulatory flexibility and streamline recordkeeping requirements in section 4.4 of the RIA. While developing the fugitive emissions monitoring program, the EPA limited monitoring, recordkeeping, and reporting requirements to include only what is necessary to meet BSER and demonstrate compliance. These streamlined requirements benefit owners and operators of well sites (including small entities).

e. Delay of Repair Due to Parts Unavailability

Comment: A commenter noted that NSPS OOOO and OOOOa allow for delay of repair beyond a unit shutdown if “valve assembly supplies have been depleted, and valve assembly supplies had been sufficiently stocked before the supplies were depleted.” The commenter notes that in the November 2021 Proposal (86 FR 63174), the EPA recognized that operators of older equipment may experience delays in obtaining replacement parts. Given current supply chain issues and the larger number of well sites, centralized production facilities, and compressor stations, the EPA should expand the current delay-of-repair requirements to include delays because of parts unavailability.

Response: Based on this comment and those summarized later in section XI.A.2.b on compressor stations, the EPA is allowing delay of repair of fugitive emissions components due to unavailability of replacement components (or parts thereof) in certain circumstances at well sites, centralized production facilities, and compressor stations. Specifically, delay of repair is allowed if replacement is required but cannot be acquired and installed within the repair timeline due to either of the following conditions: (1) replacement valve supplies have been sufficiently stocked but are depleted at the time of repair; or (2) a replacement fugitive emissions component or a part thereof requires custom fabrication. See section XI.A.2.b for our reasons for allowing delay of repair under these specified conditions, our response to the major comments on this issue, and additional details on this provision.

f. Other Changes

The EPA has made certain corrections to the regulatory text of NSPS OOOOb and EG OOOOc since the December 2022 Supplemental Proposal.

The EPA is correcting the definition of “major production and processing equipment” to add certain equipment that were inadvertently excluded in the December 2022 Supplemental Proposal. In the preamble to the December 2022 Supplemental Proposal, the EPA specifically proposed to identify natural gas-driven pneumatic controllers, natural gas-driven pneumatic pumps, and control devices as “major production and processing equipment” in the context of defining well site subcategories for the fugitive emissions monitoring and repair program of NSPS OOOOb and EG OOOOc and justifying requiring quarterly OGI monitoring where this equipment is present (87 FR 74723 and 74735). Following the publication of the December 2022 Supplemental Proposal, the EPA noticed that the draft regulatory text for NSPS OOOOb and EG OOOOc accompanying the proposal would have inadvertently adopted, without change, the definition of “major production and processing equipment” in NSPS OOOOa, which has a different fugitive emissions monitoring program for well sites than that of NSPS OOOOb and EG OOOOc; as a result, natural gas-driven pneumatic controllers, natural gas-driven pneumatic pumps, and control devices were inadvertently excluded from the definition of “major production and processing equipment” in the proposed NSPS OOOOb and EG OOOOc. The following edits were made to align the regulatory text with the EPA's intent as stated in the Supplemental Proposal:

• Added “natural gas-driven pumps” to the list of major equipment that puts a well site into the third subcategory (well sites with major production and processing equipment or centralized production facilities) at 40 CFR 60.5397b(g)(1)(iv)(C) and 40 CFR 60.5397c(g)(1)(iii)(C);
• Added “natural gas-driven pumps” to the list of major equipment that cannot be present at a small well site at 40 CFR 60.5430b and 40 CFR 60.5430c; and
• Added “control devices, natural gas-driven process controllers, natural gas-driven pumps” and “tank batteries” to the definition of major production and processing equipment at 40 CFR 60.5430b and 40 CFR 60.5430c.

Similarly, in the December 2022 Supplemental Proposal, the EPA proposed as part of the fugitive emissions standards and presumptive standards an equipment standard such that thief hatches and other openings on a storage vessel that are fugitive emissions components must remain closed and sealed at all times except during sampling, adding process material, or attended maintenance operations (87 FR 74731). However, this proposal was not reflected in the regulatory text accompanying the December 2022 Supplemental Proposal. The EPA is finalizing this requirement, which has been added to the regulatory text (see 40 CFR 60.5397b(g)(1)(ii) and (iv) and 40 CFR 60.5397c(g)(1)(i) and (iii)).

Lastly, the EPA added to the final rules definitions of single wellhead only well sites and multi-wellhead only well sites at 40 CFR 60.5430b and 40 CFR 60.5430c to avoid confusion.

2. Fugitive Emissions at Compressor Stations

In section X.A.2 of this document, the final NSPS OOOOb and EG OOOOc requirements for fugitive emissions components at compressor stations are summarized. The BSER analysis for fugitive emissions components at compressor stations is unchanged from what was presented in the December 2022 Supplemental Proposal (see 87 FR 74739–40, section IV.A.2: OGI Monitoring at Compressor Stations). In the December 2022 Supplemental Proposal, the EPA proposed the BSER as monthly AVO combined with quarterly OGI (or EPA Method 21) monitoring requirements for fugitive emissions components affected facilities located at compressor stations, which would take the form of a work practice standard. However, significant comments were received on the December 2022 Supplemental Proposal on the following topics: (1) the monthly AVO monitoring requirement and (2) delay of repair for parts unavailability. Comments on these topics and the EPA's responses are discussed here. These comments and the EPA's responses to these comments generally apply to the standards proposed in both the NSPS OOOOb and EG OOOOc. The EPA's full response to comments on the November 2021 Proposal and December 2022 Supplemental Proposal, including any comments not discussed in this preamble, can be found in the EPA's RTC document for the final rule.

a. Monthly AVO Monitoring

Comment: Some commenters claim that the monthly AVO requirement for compressor stations is unnecessary. One commenter indicated that to require monthly AVO and quarterly OGI or EPA Method 21 monitoring and recordkeeping is overly burdensome and unnecessary for compressor stations. This commenter believes that existing equipment and monitoring methods have proven effective and have minimized emissions, and believes a baseline threshold for low-volume compressor stations and periodic AVO inspections and documentation would effectively achieve the goals of the proposed requirements. Another commenter argued that, compared to state-of-the-art continuous monitoring systems, the proposed requirement for monthly AVO inspections and quarterly OGI inspections provides neither the greatest emissions reduction nor the most economical solution. This commenter encouraged the EPA to also allow continuous monitoring technology solutions as the BSER for compressor stations. On the other hand, a commenter recommended that monthly AVO inspections in addition to quarterly instrument-based leak detection and repair inspections should be required at gathering and boosting and transmission stations.

Response: For the reasons explained here, the EPA found unpersuasive those comments suggesting that the proposed fugitive emissions monitoring requirements at compressor stations, in particular monthly AVO inspections, are unnecessary or burdensome. As explained in the December 2022 Supplemental Proposal (87 FR 74739), regular AVO inspections at compressor stations can be conducted by any staff at the site without the need for any special expertise. In fact, AVO inspection was added in the December 2022 Supplemental Proposal in response to recommendations by some commenters on the November 2021 Proposal recommending AVO as a low-cost method that is effective at identifying emissions, even for small-company compressor stations. The commenters specifically noted that even though small-company compressor stations are not manned 24 hours per day, they are visited weekly, if not daily. The EPA found the comments persuasive and did not see a need to confirm the commenters' assertions by conducting its own cost analysis for conducting monthly AVO inspections for compressor stations. The EPA notes that no commenter disputed or otherwise questioned the comments described above regarding the low cost of AVO monitoring, which the EPA relied upon in its December 2022 Supplemental Proposal. With regard to the comment suggesting that OGI monitoring is unnecessary because AVO surveys during these frequent visits would effectively achieve the EPA's emission reduction goals, the EPA disagrees that AVO surveys alone ( i.e., without quarterly OGI monitoring) qualify as the BSER because OGI is needed to detect fugitive emissions that are not detectable by AVO. In addition, the EPA received no information that caused it to change its assessment that quarterly OGI monitoring at compressor stations is not cost-effective. Accordingly, the EPA is finalizing its determination that monthly AVO monitoring and quarterly OGI monitoring, in combination with repair requirements, represents the BSER for fugitive emissions components at both new and existing compressor stations.

The EPA supports the use of continuous monitoring systems to detect fugitive emissions at compressor stations. Although at this point the EPA does not have sufficient information to include this new but rapidly advancing technology in its BSER analysis, the EPA is finalizing a pathway for owners and operators to utilize continuous monitoring technologies at well sites, centralized production facilities, and compressor stations as part of the advanced methane detection technology provisions of the rule.

b. Delay of Repair Due to Parts Unavailability

Comment: Several commenters requested that a delay of repair be allowed when parts are unavailable to do the required repairs and note that the EPA requested feedback in the November 2021 Proposal (86 FR 63174) on whether to allow delay of repair due to parts unavailability. One commenter noted that delay of repair due to unavailability of valve assembly replacement supplies was included for onshore natural gas processing plants in the December 2022 Supplemental Proposal, but questions why it was not included for other natural gas industry segments that include similar arrays of high-pressure gas valves and rely on the same types of replacement supplies. Another commenter notes the same difference and adds that the array of large valves that require special service for parts or replacement for compressor stations may be more complicated than at some natural gas processing plants. Additionally, the same commenter says that supply chain delays have lengthened delivery times for replacement parts and that operators can ensure that replacement parts are ordered in a timely manner but cannot control how quickly the parts will arrive. Both commenters discuss the timelines for delivery of replacement valves, which ranged between 16 and 40 weeks, depending on size, at the time of the comments.

A commenter also asserted that larger, older compressor stations were expanded over time with different compressor sizes, types, and vintages, resulting in a large array of unique valves at compressor stations. The commenter continued, saying that parts are not interchangeable between different manufacturers, models, or even different vintages of the same equipment and that if a part breaks on an older piece of equipment, the comparable part that is used for new compressors may not be the right size or configuration for the older equipment. In such cases, the appropriate parts for that equipment will need to be custom fabricated; manufacturers do not maintain an inventory of expensive parts, unique parts, or parts for older equipment. The commenter estimated that the timeline for custom fabrication of station valves can require 4 to more than 12 months, depending on the size and uniqueness of the part. Another commenter explained that in their experience, the parts most likely to be in short supply are large, unique valves used for compressor isolation or isolating sections of a facility or pipeline; these valves are not standard items, and they come in many configurations. The commenter explained that, given the size and unique specifications of each valve, it is not practical or economical to maintain a significant inventory of such items. They added that such items may require special fabrication with lead times of many months. As an example, the commenter described a recently identified leak on a 16-inch valve. Upon investigation, they determined that repair ( e.g., replacing subcomponents of the large valve) was not possible and an exact replacement valve could not be ordered because the valve was obsolete. Investigation into a new replacement indicated a lead time on the order of at least 18 weeks.

Commenters also recommended that delay of repair due to parts unavailability should extend to parts other than valves. One commenter stated that compression includes an array of parts associated with the compression driver, the compressor, and associated valving, piping, and other processing equipment. A valve is one example of a part type that may not be available for repair or replacement, but other large, unique legacy parts associated with other legacy process equipment may need to be machined or more major components may need to be constructed.

Conversely, another commenter contended that the availability of parts is not a valid concern because replacement parts could be easily procured, and operators could stockpile fugitive emission components and parts thereof prior to this rule's requirements coming into effect.

Commenters also responded to the EPA's solicitation of input on the timeline for repair upon receipt of the part and any associated documentation. One commenter suggested that repairs must be completed within 30 days following the receipt of the replacement part, provided that conducting the repair would not require a unit or wellhead shutdown and that, if shutdown was required, the repair should occur during the next scheduled maintenance shutdown. Similarly, another commenter requested that the EPA provide in the regulatory text that, where no shutdown or blowdown is needed, the operator should repair the leak within 30 days after receiving the parts. The commenter requested that where a repair requires a shutdown or blowdown, the regulatory text allow the repair to be performed during the next scheduled shutdown for maintenance after receipt of the requisite parts, not to exceed 2 years. The commenter stated that this will avoid unnecessary blowdown emissions. One commenter recommended that the required recordkeeping follow current NSPS OOOOa criteria, where the operator documents the delay basis and repair schedule. Another commenter suggested that the operator be required to support the necessity of delay of repair due to parts unavailability through rigorous documentation, including but not limited to: a reasonable explanation of why the operator did not have a spare part on hand; a justification of why the equipment failure was not foreseeable at any point from the date of the proposed regulations until the date of failure; proof that such failures are not common at similar compressor stations of similar age; maintenance and inspection records supporting the non-foreseeability of the failure; proof and date that the replacement part was ordered immediately upon detection; and proof that the part was installed as quickly as possible upon receipt.

Response: In response to these comments, the EPA is allowing delay of repair that requires replacement where the replacement cannot be acquired and installed within the repair timeline due to either of the following conditions: (1) Replacement valve supplies have been sufficiently stocked but are depleted at the time of repair; or (2) a replacement fugitive emissions component or a part thereof requires custom fabrication. In either situation, the required replacement must be ordered within 10 calendar days after the first attempt at repair. The repair must be completed within 30 calendar days after receipt of the replacement or during the next scheduled shutdown for maintenance after the replacement is received (if the repair requires a shutdown). Operators must document the date the leak was added to the delay-of-repair list, the date the replacement fugitive emissions component or part thereof was ordered, the anticipated delivery date, and the actual delivery date as part of their fugitive emission survey records.

The EPA acknowledges that during the 2016 rulemaking promulgating NSPS OOOOa and the 2021 amendments, the EPA received comments requesting that the EPA allow delay of repair due to parts unavailability. The EPA declined to do so in 2016, explaining that “[t]he EPA does not agree that unavailability of supplies or custom parts is a justification for delaying repair ( i.e., beyond the 30 days for repair provided in this final rule) since the operator can plan for repair of fugitive emission components by having stock readily accessible or obtaining the parts within 30 days after finding the fugitive emissions.” 81 FR 35824, 35858. In 2021, the EPA similarly expressed that it “does not agree a lack of parts is a sufficient justification to delay.”

However, regarding the comment noting that the standards (and presumptive standards) for onshore natural gas processing plants in the proposed NSPS OOOOb and EG OOOOc would have allowed delay of valve repair due to depletion of valve supplies and requesting that the EPA allow the same in the fugitive emissions standards for well sites and compressor stations, the EPA concludes that well sites and compressor stations face some of the same valve assembly supply constraints as onshore natural gas processing plants and that operators can ensure timely ordering of replacement fugitive components or parts thereof but cannot control replacement delivery timelines. Thus, the EPA is including similar delay-of-repair provisions for valve assembly supplies that had been sufficiently stocked but are depleted at the time of the required repair for wellsite and compressor station fugitives as for onshore natural gas processing plants in this rule. The final fugitive emissions standards for well sites and compressor stations under NSPS OOOOb (and presumptive standards under EG OOOOc) allow delay of repair due to depletion of supplies for valves only. This is consistent with the standards for onshore natural gas processing plants, which have provided such allowance for valves only since the standards were first promulgated in 1985, and the EPA has not received information showing difficulty of repair due to well-stocked supplies of other fugitive emissions components or parts thereof that were depleted before repair could be completed.

In addition to allowing delay of repair of valves due to depletion of supplies as described above, the final rule allows delay of repair where repair requires replacement of a custom-made fugitive emissions component or a part thereof. The comments on the November 2021 Proposal and December 2022 Supplemental Proposal also include supporting information on exceptional, infrequent circumstances where a replacement part requires custom fabrication. Specifically, the information includes insight into the quantity and variety of vintage equipment at compressor stations, the unlikelihood of manufacturers' stocking replacement parts for vintage equipment and thus the need for custom fabrication of replacement supplies, and the timeline for fabrication and delivery of custom supplies. Recent examples of extensive supply chain delays have highlighted that a delay of repair may be needed for circumstances beyond an owner or operator's control. In light of the information on the challenges and the time needed to acquire parts that require custom fabrication and the current supply chain issue, we are including in the final NSPS OOOOb and the model rule in EG OOOOc provisions for delay of repair where replacement is required and the replacement fugitive emissions component or a part thereof requires custom fabrication. As described above, for delay of repair under either of the two specified conditions, the final rule prescribes specific timeframes for ordering and installing the parts to ensure that repair is completed in a timely manner, as well as the specific records that must be kept to demonstrate compliance with these requirements.

B. Advanced Methane Detection Technology Work Practices

In the December 2022 Supplemental Proposal, the EPA proposed a revised alternative fugitive emissions monitoring and repair program for new, modified, or reconstructed fugitive emissions sources ( i.e., collection of fugitive emissions components located at well sites, centralized production facilities, and compressor stations). This program was intended to provide owners and operators with the flexibility to use advanced methane detection technologies in lieu of the ground-based OGI and AVO surveys that the EPA had proposed for fugitive emissions sources. Among other things, the December 2022 Supplemental Proposal included a proposed “matrix” that would specify different screening frequencies corresponding to a range of minimum detection thresholds, in contrast to the single screening frequency and detection level proposed in the November 2021 Proposal. In addition, the EPA proposed to allow owners and operators the option of using continuous monitoring technologies as another alternative to ground-based OGI and AVO surveys and proposed long- and short-term emission rate thresholds that would trigger corrective action. The EPA also proposed monitoring plan requirements for owners and operators that chose to implement the alternative fugitive emissions monitoring approach and proposed a clear and streamlined pathway for technology developers and other entities to seek the EPA's approval for the use of advanced methane detection technologies under this alternative option.

This section of this document presents a summary of significant comments received on advanced methane detection technologies and the EPA's response to those comments, as well as certain changes in the final standards for using advanced methane detection technologies for monitoring fugitive emissions components at new and existing facilities and for conducting continuous inspection and monitoring for covers and closed vent systems. For other comments on the proposed program and the EPA's response thereto, see chapter 5 of the RTC document, Advanced Methane Detection Technologies. For final standards and requirements that have not changed since the December 2022 Supplemental Proposal, the supporting rationales are not reiterated in this preamble. The rationale for those standards and requirements can be found in section IV of the preamble for the December 2022 Supplemental Proposal (87 FR 74702 at 74722–810, December 6, 2022).

1. Periodic Screening

a. Matrix Table and Screening Frequency

Comment: The EPA received considerable support for the flexibility to use advanced methane detection technologies in lieu of using OGI, EPA Method 21, or AVO to monitor fugitive emissions components in response to the December 2022 Supplemental Proposal. One commenter supported the proposed frequencies in the matrix, noting that their independent equivalency modeling matched the results of the EPA's FEAST modeling across a variety of scenarios, and supported the EPA's choices of model inputs that made assumptions based on nationally applicable factors and considerations, as these inputs apply across the country to sources in different oil and gas producing regions and basins. Other commenters raised concerns that the EPA's FEAST modeling overestimates the effectiveness of AVO and OGI, resulting in matrix frequencies that are overly stringent. Another commenter discussed the potential use of an alternative emission rate distribution in the model, from a study that included a larger range of emission rates than was used in the EPA's modeling.

A commenter considered the minimum detection thresholds and monitoring frequencies in the proposed matrix to be insufficiently differentiated between the tiers with respect to detection levels. Several commenters raised concern that the 30 kg/hr periodic screening tier provides a less stringent work practice for emissions reduction and urged the EPA to remove the 30 kg/hr detection tier.

Another commenter stated that advanced methane detection technologies are evolving rapidly and are a key component of the commenter's strategy for broader emission reductions. The commenter believed that these technologies have the potential to be more effective at finding leaks on a broader scale, allowing for faster detection and mitigation, leading to a greater reduction in methane emissions. This commenter was concerned that there may be inadvertent disincentives that are contrary to the intent of the EPA, which is to encourage innovation resulting in meaningful emissions reductions. The commenter was concerned that disincentives may encourage operators to simply continue their existing OGI survey programs as the default option, which could hinder broad development and adoption of advanced methane detection technologies.

Response: Regarding the modeling conducted to develop the periodic screening matrices in the December 2022 Supplemental Proposal, while the EPA acknowledges there are alternative inputs available for the models, we incorporated the best available information from recent studies to characterize a distribution for both common leaks and super-emitters. The results of our fugitive emissions modeling fell within the ranges observed in other literature assessments. As mentioned above, we received supportive comments for our modeling. The commenters who expressed otherwise provided limited additional peer-reviewed data with which we could revise our model assumptions; much of the data focused on studies collected using a singular technology ( e.g., aerial survey), and the emission distribution appeared to be weighted toward emissions this specific methane detection technology could identify. While the EPA's emission distribution in our model also was developed using studies conducted with aerial surveys, we augmented that distribution with ground-level studies to get a more complete emission distribution, including the lower-level emissions. Therefore, we believe the results from the modeling conducted for the December 2022 Supplemental Proposal are well-supported.

With the continued development and deployment of advanced methane detection technology, we expect further study on the distribution of methane emissions from this sector, in particular after promulgation of this rule providing a pathway for the use of advanced technologies. As additional studies are conducted on emission distributions across this sector, it is possible that the underlying emissions rate distribution in our modeling could potentially be updated in the future. However, the inputs in the modeling conducted for the December 2022 Supplemental Proposal were based on the best information available to the EPA during this rulemaking. Therefore, we continue to believe that the modeling results are well-supported and appropriate for the development of the periodic screening matrices.

In this final rulemaking, the EPA finalized the proposed matrices tables (tables 3 and 4 in NSPS OOOOb and EG OOOOc) with some adjustments in response to comments. Several commenters questioned whether an annual OGI survey is necessary in order for the use of certain periodic screening technologies to be equivalent to the fugitive emissions monitoring requirements discussed in section XI.A of this document. Based on the comments we received, the EPA reviewed the modeling results, reexamined the effectiveness of an annual OGI survey on the matrix tiers, and evaluated the uncertainty in the modeling results. We found that for the lower tiers of the matrix tables (corresponding to the most sensitive advanced methane detection technologies), the effectiveness of the annual OGI survey in reducing methane emissions in the FEAST model was minimal. Further, we found that at the highest tiers of the matrix (corresponding to the least sensitive advanced methane detection technologies), the annual OGI survey accounted for the bulk of the modeled emission reductions, and the periodic screening itself yielded relatively small reductions in emissions. Based on this additional review, we are revising the periodic screening matrices tables in the final rule by removing the proposed highest tier corresponding to the least sensitive technologies (≤30 kg/hr) and by removing the proposed requirement to conduct an annual OGI survey at the lowest detection threshold tier ( i.e., 1 kg/hr) in table 1 (which applies to well sites, centralized production facilities, and compressor stations subject to AVO inspections with quarterly OGI monitoring surveys). We have also made a small adjustment in the monthly survey.

The EPA is finalizing the proposed matrices (with some adjustments as described above), which the EPA believes reflect at least the same levels of emission reductions as those from complying with the required fugitive emissions work practice standards for well sites, centralized production facilities, and compressor stations. In addition, in response to comments on the importance of incentivizing the use of advanced methane detection technologies, the EPA is including in the final rule an interim matrix in lieu of table 1 that will apply for the next 2 years. The EPA agrees with the comments that advanced methane detection technologies have the potential to be more effective at finding leaks more quickly than traditional ground-based fugitive emission surveys; therefore, it is important to develop a framework that encourages innovation and the continued development of advanced methane detection technologies. The EPA acknowledges that these technologies will only continue to develop if owners and operators have a desire to implement them. Based on our current understanding of the state of advanced methane detection technologies, while there are some technologies that can measure at the lowest detection threshold levels in the periodic screening matrices under certain conditions, we currently do not have available data on any technologies that can achieve these minimum detection thresholds at all sites and in all conditions. Because these technology developers have had less than a year (since publication of the December 2022 Supplemental Proposal) to understand and test the proposed target detection thresholds the technologies need to meet, there has not been adequate time to develop data that push the detection thresholds down to the lowest levels of the proposed periodic screening matrix (at 1 to 2 kg/hr). For the reason explained above, it is understandable that there may be some reluctance at this time to use such technologies to comply with NSPS OOOOb at these very low detection thresholds until more data is generated to confirm their detection capabilities. We believe that, if given opportunities to use the advanced technologies, over time users will show that these technologies can meet the minimum detection thresholds in these lowest levels of the periodic screening matrix in table 1. We therefore agree with the commenter that it is critically important to incentivize the early adoption of these alternative technologies. To that end, as part of the final rule, we have developed an interim periodic screening that will apply in lieu of the matrix table for well sites, centralized production facilities, and compressor stations subject to AVO inspections with quarterly OGI monitoring surveys (table 1 in NSPS OOOOb) for the next 2 years ( i.e., until March 9, 2026). Under this interim periodic screening matrix, the lowest detection threshold is ≤3 kg/hr, and it requires quarterly screening frequency. While we are increasing the minimum detection threshold to ≤3 kg/hr in this interim 2-year period to incentivize the use of advanced technologies, the EPA expects that these technologies will be able to achieve much better ( i.e., lower) detection thresholds in many use cases, which will be reflected in the records once a technology has been approved by the EPA as an alternative and deployed for purposes of NSPS OOOOb. At the end of the interim 2-year period, the periodic screening matrix in table 1 of NSPS OOOOb, which sets survey frequencies for lower detection thresholds (≤1 kg/hr and ≤2 kg/hr), will apply. The EPA has chosen not to provide an interim periodic screening in lieu of the matrix table for well sites, centralized production facilities, and compressor stations subject to AVO inspections with semiannual OGI monitoring surveys (table 2 in NSPS OOOOb). The periodic screening matrix for these sources already allows using an advanced methane detection technology with a detection threshold of <5 kg/hr level. Because we anticipate owners and operators will conduct the screenings of all their sites (those subject to table 1 and those subject to table 2) on the same schedule and table 2 already accommodates the interim periodic screening level for table 1, EPA has determined that it is unnecessary to create an interim periodic screening for sites subject to table 2.

Comment: Several commenters asked that the EPA allow NSPS OOOOa sources to comply with the advanced methane detection technology provisions in NSPS OOOOb. One of these commenters requested that the EPA consider mechanisms to enable sources subject to NSPS OOOOa to demonstrate compliance with the fugitive emission requirements in NSPS OOOOa using any advanced methane detection technologies approved in NSPS OOOOb prior to the effective date of state or Tribal plans approved under EG OOOOc. Another commenter raised concerns that the time needed to seek approval to use these advanced methane detection technologies for existing sources through the AMEL process and EG OOOOc state plan implementation could take years.

Response: The EPA agrees with the suggestion to allow a mechanism outside of the AMEL process to allow existing facilities subject to NSPS OOOOa to use advanced methane detection technologies. We agree that a comprehensive periodic screening program that uses an advanced methane detection technology approved by the EPA under NSPS OOOOb in which all the emissions detected are repaired in accordance with NSPS OOOOb will result in emission reductions similar to or better than the reductions under the existing fugitive emissions work practice at well sites and compressor stations in NSPS OOOOa. However, the periodic screening matrices in NSPS OOOOb and in EG OOOOc reflect the overall fugitive emissions reductions equivalent to the reductions that would be achieved for that site in the standard fugitive emissions work practice using OGI and AVO under NSPS OOOOb (and presumptive standards under EG OOOOc), which includes equipment not included in the definition of “fugitive emissions component” in NSPS OOOOa. The EPA can only determine that the same or better emission reductions are achieved if an owner or operator complies with the advanced methane detection technology work practices in NSPS OOOOb by repairing all fugitive emissions, including emissions from equipment not included in the definition of “fugitive emissions component” in NSPS OOOOa, such as uncontrolled tanks, and performing required investigative analyses. Therefore, as discussed in section IX.C of this preamble, we are amending the regulatory text in NSPS OOOOa to include a provision that compliance with the advanced methane detection technology work practices approved under NSPS OOOOb will be deemed compliance with the applicable fugitive emissions standards for the same facility in NSPS OOOOa.

b. Technology Flexibility

Comment: Commenters encouraged the EPA to incorporate a pathway into the final rule to allow for the use of a combination of technologies, both traditional and advanced, to achieve equivalent emissions reductions. The EPA received several comments requesting additional flexibility in the matrix, including the allowance to use multiple technologies at a single site in a layered or tiered fashion. Commenters were concerned that by not conducting equivalency modeling for a combination of alternative technologies, the proposed matrix would fail to provide sufficient flexibility for owners and operators that find it necessary to apply multiple advanced technologies due to equipment limitations, operating conditions, or economic factors. Several commenters discussed that the matrix should account for the occasional need to deploy different monitoring technologies due to seasonal environmental conditions, noting that inclement weather, including wind, rain, and ground snow cover, can adversely affect methane detection performance. A commenter recommended allowing OGI surveys during the months when advanced detection technologies cannot be deployed.

Some commenters suggested that continuous monitoring technologies may fit within the periodic screening framework and urged the EPA to consider such technologies within that context. Another commenter recommended that continuous monitoring be incorporated with periodic screening to create a single framework for alternative methane detection technology.

Response: The EPA agrees that the rule should allow for the use of multiple technologies at a single site and finds that this approach would provide valuable flexibility for owners and operators while continuing to achieve a degree of monitoring performance that is equivalent to the fugitive emissions monitoring requirements in this rule. Therefore, in the final rule we are allowing the use of one or more alternative test methods for advanced methane detection technology to conduct periodic screening. The frequency for conducting periodic screening events will be based on the methane detection technology with the highest sensitivity. For example, if an owner or operator uses methane detection technology with a detection threshold of ≤10 kg/hr, the owner or operator may choose when conducting bimonthly screening events to use any methane detection technology with a detection threshold of ≤10 kg/hr. We also agree that environmental conditions can adversely affect some methane detection technologies. In the final rule we allow the owner or operator to conduct an OGI survey in place of a periodic screening event at any time. The planned use of multiple technologies, including OGI, must be incorporated into the site-specific monitoring plan.

The EPA also agrees that continuous monitoring technologies can fit within the periodic screening framework, especially those technologies that may not be able to comply with the requirements in the continuous monitoring framework. While it was not explicitly stated in the December 2022 Supplemental Proposal, we intended for continuous monitoring technology to be considered as a candidate for the periodic screening approach. The EPA continues to consider the periodic screening approach a valid pathway for continuous methane detection technology.

c. Spatial Resolution

Comment: Several commenters discussed that some measurement technologies have tighter spatial resolution which may enable the detection of equipment-specific emissions, and as such, use of these technologies may not require a follow-up OGI survey of the entire site. One commenter mentioned that one may be able to conclusively identify the fugitive emissions component with certain measurement technologies. Another commenter urged the EPA to require follow-up OGI surveys only within the general area of detection from a periodic screening event.

Response: The EPA finds these comments compelling and in the final rule is incorporating the concept of spatial resolution of measurement technology into the follow-up actions an owner or operator must take when a periodic screening event results in a confirmed detection. We have included three classifications for spatial resolution in the final rule: (i) facility-level spatial resolution, meaning an alternative test method with the ability to identify emissions within the boundary of a well site, centralized production facility, or compressor station; (ii) area-level spatial resolution, meaning a technology with the ability to identify emissions within a radius of 2 meters of the emissions source; and (iii) component-level spatial resolution, meaning a technology with the ability to identify emissions within a radius of 0.5 meters of the emissions source. Entities requesting an alternative test method for advanced methane measurement technology would identify and verify the spatial resolution of the measurement technology as part of the request.

In the final rule, for periodic screening events conducted with technologies that have facility-level spatial resolution, we have maintained the follow-up actions an owner or operator must take in response to a confirmed detection that were outlined in the December 2022 Supplemental Proposal. However, for periodic screening events conducted with technologies that have area-level or component-level spatial resolution, we have targeted the follow-up actions the owner or operator must take. The follow-up monitoring that must be conducted for a confirmed detection during a periodic screening event using a technology with area-level spatial resolution includes a monitoring survey of all the fugitive emissions components located within a 4-meter radius of the location of the confirmed detection and, if the confirmed detection occurred in a portion of a site with a storage vessel or closed vent system, inspection of all covers and closed vent systems that are connected to all storage vessels and closed vent systems that are within a 2-meter radius of the location. The follow-up monitoring that must be conducted for a confirmed detection during a periodic screening event using a technology with component-level spatial resolution includes a monitoring survey of all the fugitive emissions components located within a 1-meter radius of the location of the confirmed detection and, if the confirmed detection occurred in a portion of a site with a storage vessel or closed vent system, inspection of all covers and closed vent systems that are connected to all storage vessels and closed vent systems that are within a 0.5-meter radius of the location. The EPA is requiring inspection of the entire closed vent system in order to identify a potential cause of the failure. The EPA has also incorporated the requirement to verify the spatial resolution of a measurement technology as part of the alternative test method provisions.

d. Root Cause Analysis

Comment: Several commenters supported the requirement that an owner or operator investigate the source and cause(s) of significant emissions found through periodic screening events. However, many commenters took exception to the proposed use of “root cause analysis” for investigating potential causes of emissions. One commenter noted that the concept of “root cause analysis” is embedded in numerous other regulatory and non-regulatory programs and has varied meaning and purpose in each application. Another commenter asserted that the phrase “root cause analysis” has connotations that lead to a much more involved process than the EPA appears to envision in this rule. Many of these commenters suggested that “root cause analysis” be replaced by “investigative analysis,” broadly meaning the owner or operator must determine what caused the emissions event to occur and take steps to ensure that it will not happen again.

Response: The EPA agrees with the concern raised by commenters and in the final rule requires an investigative analysis as opposed to a root cause analysis. For the purpose of this final rule, an investigative analysis is the determination of the underlying primary and other contributing cause(s) of the emissions event. For a control device, the investigative analysis must include a determination that the control device is operating in compliance with the applicable requirements, and if not, what actions are necessary to bring the control device into compliance and prevent future failures of the control device from the same underlying cause(s). For a cover or closed vent system, the investigative analysis must include a determination of whether the system was operated outside of the engineering design analysis and whether updates are necessary for the cover or closed vent system to prevent future emissions from the cover or closed vent system.

2. Continuous Monitoring

a. Continuous Monitoring System Criteria

Comment: Several commenters requested that the framework for continuous monitoring set action levels based on the concentration of emissions as an alternative to the action levels based on the mass rate of emissions in order to allow owners and operators to use a broader range of continuous monitoring systems. One commenter supported the EPA's inclusion of health checks for devices within the continuous monitoring system but suggested that the health checks rely on functionality instead of connectivity. Several commenters requested more flexibility as to how often these systems must transmit data. Other commenters contended that flexibility in the downtime requirement is necessary, as typical downtime can be 4 or more days per month for remote locations.

Response: The EPA agrees that it is important to facilitate the use of a broad range of continuous monitoring systems in the advanced methane detection technology provisions of this rule, because they allow more rapid detection of leaks and thus an enhanced ability to promptly respond and prevent emissions. As such, we have expanded the definition of a continuous monitoring system to allow systems beyond those that determine mass emission rate only by noting these systems must determine the “mass emission rate or equivalent.” The EPA also agrees with the commenter that the health checks of the system can be based on function rather than connectivity and that more flexibility in the transmission of data is appropriate. In the final rule we require data to be transmitted at least once every 24 hours.

The EPA does not agree that additional flexibility in the downtime requirements is appropriate, even for remote locations. In order to demonstrate that a continuous monitoring system is equivalent to the required OGI/AVO monitoring for fugitive emissions component affected/designated facilities, it is important for these systems to collect and analyze data with a limited amount of downtime. If the downtime is too great, we cannot ensure that the emissions reductions achieved by the alternative continuous monitoring method are equivalent to those from the work practice that has been determined to be BSER. If a continuous monitoring system cannot meet the operational downtime in the final rule and an owner or operator does not want to conduct surveys with OGI or EPA Method 21, the owner or operator may choose to use a continuous monitoring system that does meet the downtime requirement in the rule or may choose to use the alternative periodic screening option.

b. Detection Threshold

Comment: Several commenters did not agree with the requirement in the December 2022 Supplemental Proposal that continuous monitoring systems be capable of measuring emissions at an “order of magnitude” lower than ( i.e., 1/10 of) the proposed action levels. One commenter mentioned that this requirement is overly prescriptive and appears to be technology-specific rather than outcome-based and technology-agnostic.

Response: The EPA agrees with the commenters and in the final rule requires a detection threshold of 0.40 kg/hr (0.88 lb/hr) above a baseline, which is based on one-third the action level. The requirements in the December 2022 Supplemental Proposal were based on the method detection limit requirements for alternative test methods in the fenceline monitoring program in the refinery rule. Requiring alternative measurement technologies used in the refinery fenceline monitoring program to measure an order of magnitude below the action level is appropriate because in that program, the difference between the high and low sample results during a measurement period are used to calculate the site's benzene concentration difference; therefore it is important to be able to differentiate the low-concentration measurements for benzene we expected around some refineries. In this final rule, the requirement for technology to be able to detect methane an order of magnitude below the action level is unnecessarily restrictive for real-time systems measuring methane mass emission rates, which may use concentration, meteorology, and modeling to calculate these rates, all of which have uncertainty built into the detection limit. Because these systems will be measuring a mass emission rate and not a concentration difference, it is less important to differentiate between the measurements across the site. It is only important that the technology be able to measure methane at background levels in order to be able to develop a site-specific baseline for methane, and methane is ubiquitous in the atmosphere at levels that should not present a concern for detection. For these reasons, we are requiring continuous monitoring alternative methane detection technologies to have a sensitivity of one-third of the lowest action level, 0.4 kg/hr (0.88 lb/hr). We note this requirement is also consistent with the EPA's approach for setting emission limits that are at least three times the representative detection limit. Such an approach ensures that the standard is at a level that addresses measurement variability and is in a range that can be measured with reasonable precision. Requiring the detection limit of continuous monitoring technologies to be at least one-third of the action level will ensure that measurements made near the action level are of reasonable precision.

c. Site-Specific Emissions Baseline

Comment: Several commenters raised concerns over the long-term 1.2 or 1.6 kg/hr action levels, because these emission rates are well below the baseline emissions for many sites. Other commenters believed it critical that the follow-up response actions are tied not to detection limits but to action levels and that those action levels be levels that account for the site's baseline emission rates. One commenter noted that other regulated sources can contribute to substantial temporal variability in the baseline emission rate and provided the example of methane slip from gas-fired compressors, which can vary depending on compressor operating setpoints and maintenance. An additional commenter suggested that the concept of a baseline be used to establish an emissions profile and action levels be incremental to that baseline. The commenter further suggested that since the baseline is meant to capture normal emissions from the facility, while responses to the long-term and short-term action levels are meant to reduce fugitive emissions, the baseline period should be 90 days.

Response: The EPA agrees that the action level should be incremental to the site-specific baseline emissions. In the final rule, we are revising the action level to be a mass emission rate that is above the site-specific baseline emissions. Based on the recommendations of the commenters, we are also establishing requirements for how and when the determination of the site-specific baseline is performed. The baseline emissions must be established after the initial installation of a continuous monitoring system or when there is a major change in the processing equipment at the site. The owner or operator must inspect and repair all fugitive components, covers, and closed vent systems and verify that control devices are in compliance with applicable requirements prior to starting the baseline determination period.

The EPA disagrees with the suggested 90-day baseline period. We consider 30 days sufficient time to measure the variability of a site. Therefore, the baseline emissions are determined as the mean emission rate for 30 operating days, minus any time periods where maintenance events are conducted. This site-specific baseline emission rate must be no more than 10 times the site's applicable 90-day action level ( i.e., 16 kg/hr for well sites with major production and processing equipment (including small well sites), centralized production facilities, and compressor stations, or 12 kg/hr for wellhead only well sites).

d. Mass Emission Rate Reduction Plan

Comment: One commenter mentioned that the December 2022 Supplemental Proposal was not clear on how operators would deal with subsequent increases to the rolling average if corrective action had already been taken for the initial event.

Response: The EPA agrees with the commenter that the December 2022 Supplemental Proposal was not clear on how to handle this situation. In the final rulemaking, owners and operators who conduct continuous monitoring with advanced methane detection technologies will initially (prior to conducting continuous monitoring) develop a site-specific baseline that accounts for normal process fluctuations. This site-specific baseline will be subtracted from the monitored emissions when determining whether there is an exceedance of an action level. As such, the EPA anticipates that there should not be instances where the rolling average emissions continue to increase once the primary and underlying causes of the original exceedance of the action level is addressed.

3. Alternative Test Method

a. Administrator Delegation

Comment: Several commenters expressed that the alternative test method approval process should enable expeditious and thorough review of advanced technologies. An additional commenter supported the EPA's proposal to allow operators to utilize the matrix to comply with CAA section 111(h)(l) and to approve alternative test methods under 40 CFR 60.8(b)(3), as this process enables operators to deploy technologies meeting the specifications of the matrix and encourages greater use of alternative technologies that can better detect emissions, resulting in greater emission reductions.

Response: The EPA agrees that the alternative test method review process should be expeditious without sacrificing thoroughness. To that end, the EPA proposed a process for approving alternative test methods in 40 CFR 60.5398b(d), which is similar to the process in 40 CFR 60.8(b)(3) but specifically tailored towards the types of advanced technologies that are in use or under development in the oil and natural gas sector.

b. Super-Emitter Technology

Comment: The EPA received several comments on the December 2022 Supplemental Proposal regarding the lack of criteria for remote sensing technologies used in the Super Emitter Program. One of these commenters believed these criteria should be based on the same proposed tenets as those for the advanced methane detection technologies, including detection limits based on a probability of detection curve and quantification accuracy. Another commenter stated that the EPA should use the alternative test method approval process to approve technologies for use in the Super Emitter Program. Another commenter maintained that third parties who are certified under the Super Emitter Program should not face a higher barrier to monitoring than operators themselves.

Response: The EPA agrees with these comments. In this final rule, the EPA has included provisions to approve technologies used in the Super Emitter Program in 40 CFR 60.5398b(d), which are the same provisions that will be used to approve alternative methane detection technologies used by owners and operators. The EPA pre-approving the remote sensing technologies used by third parties under the Super Emitter Program will provide additional confidence in the data being provided by the third parties to the EPA, which will allow for expedited review of the data and help to ensure the data provided to the owner or operator is accurate and actionable.

c. Request for Alternative Test Methods

Comment: One commenter requested we remove the requirement that an alternative test method, such as a continuous monitoring system, must be “commercially available” to be approved for use under the rule, as this unintendedly prevent in-house technology developed by an owner or operator from being used. Several commenters requested that the EPA clarify the information companies must include in a request for an alternative test method. One commenter added that this clarification is necessary to support the EPA's ability to efficiently review and approve complete applications that demonstrate equivalent or better methane detection and reductions. Another commenter suggested that technology vendors include proof of results in their applications, including an accredited third party's validation, as they relate to detecting methane leak events, including field-proven evidence and technology validation accurately capturing events for a given range of detection and quantification thresholds. Several commenters requested that the EPA clarify what is meant by commercial availability of alternative leak detection technologies.

Response: Based on the comments received, in the final rule the EPA has changed the term describing the alternative technology from “commercially available” to “readily available.” We have also provided clarification that readily available technology includes equipment or technology developed by an owner or operator for internal use and/or use by external partners. The EPA has also clarified the information that must be included in a request for an alternative test method for advanced methane detection technology. In the final rule, the request for an alternative test method must include contact information, description of the measurement technology, scientific theory of the measurement, potential limitations, how the measurement is translated to a mass emission rate, detailed workflow, information on any models used, a-priori methods, how all data are collected and transformed from measurement to end user, supporting information verifying that the technology meets the claimed detection threshold(s) as applied in the field, including published reports produced by the candidate or outside entity, standard operating procedures, formal alternative test method procedures, and information on the spatial resolution of the measurement technology. Requests for an alternative test method for advanced methane detection technology must be submitted to the EPA through the alternative methane detection technology portal at https://www.epa.gov/emc/oil-and-gas-alternative-test-methods.

C. Super Emitter Program

In the December 2022 Supplemental Proposal we proposed the Super Emitter Program to establish a pathway by which an EPA-certified entity ( i.e., third-party notifier) may provide credible, well-documented identification of a super-emitter emissions event using one of several permitted remote-sensing technologies and approaches to the responsible owner or operator. Once notified of the event at a site they own or operate, owners and operators would be required to perform a root cause analysis to identify the source of the super-emitter event and take corrective actions to address the emissions source. As described in this section, the EPA received comments on the following aspects of the Super Emitter Program: (1) Statutory authority for the program, (2) remote sensing methane detection technology, (3) certification of third parties, (4) notifications by third parties, and (5) requirements for owners and operators. In response to these comments, the EPA has made targeted changes to the Super Emitter Program, which are described in detail in section X.C of this document.

Provided in this section are some of the significant comments on the proposed program and the EPA's response thereto. For other comments on the proposed program and the EPA's response thereto, see chapter 14 of the RTC document, Super Emitter Program.

1. Statutory Authority

In the December 2022 Supplemental Proposal, the EPA had proposed for comment two legal frameworks in support of the Super Emitter Program (87 FR 74752). Under the first legal framework, the EPA would treat a super-emitter event as a separate and distinct affected facility under NSPS OOOOb (or a designated facility under EG OOOOc), and the proposed BSER for this affected facility/designated facility was the requirement that an owner or operator, upon receiving a notice of a super-emitter event from an EPA-certified third party, must take action to identify and address the source of the super-emitter event. Under the second legal framework, the Super Emitter Program functioned as an additional compliance assurance measure for affected facilities/designated facilities subject to numeric performance standards. Under that second framework, for fugitive emissions component affected facilities/designated facilities, the Super Emitter Program was proposed as part of the BSER for the fugitive emissions standard at well sites and compressor stations, which would include a requirement to repair components that have been identified as the source of a super-emitter event. As discussed below, in response to the comments on both legal frameworks, the EPA has revised the Super Emitter Program since the December 2022 Supplemental Proposal. The final Super Emitter Program, which the EPA is establishing pursuant to the authorities provided by CAA sections 111 and 114(a), is based on the second legal framework; however, as revised, it will be the EPA, not a third party, that will notify owners and operators of super-emitter events, and such notification will be based on data submitted by EPA-certified third parties using EPA-approved detection technology, and will be issued only after the EPA has reviewed the data and deemed it to be complete and accurate. In addition to the responses to comments below, please also see section X.C of the preamble for a more detailed discussion of the legal frame for the final Super Emitter Program.

Comment: A number of commenters question the legality of the first proposed legal framework, which defines a super-emitter event as an affected facility/designated facility. One commenter notes that the EPA may only regulate two types of sources under CAA section 111(b) and (d): new sources (including modified sources) and existing sources; however, a super-emitter source is created by an event, not construction or modification, and therefore is neither a new nor existing source under CAA section 111. Another commenter similarly questions the legality of a super-emitter affected facility/designated facility, noting that it is created by a third-party notification and could not be said to exist prior to such notification.

Response: Because the EPA is finalizing the program based on the second legal framework, the legal concerns raised by these commenters regarding the creation of a new super-emitter affected/designated facility under the first legal frame are now moot.

Comment: One commenter states that the EPA's focus on compliance assurance fits particularly well with the goals of the program and with the problem of super-emitters. Emissions events exceeding 100 kg/hr indicate major problems at the site resulting from either noncompliance or serious operational issues. The commenter stated that the EPA has broad authority under CAA section 114 to accept and use third-party monitoring data for purposes related to CAA section 111, including ensuring compliance. The commenter asserted that the Super Emitter Program does not and should not replace obligations on the part of owners and operators to reduce methane emissions from affected and designated facilities under the rules. Rather, the commenter views the Super Emitter Program as an additional backstop to ensure that the unique problems posed by super-emitters are timely addressed.

Another commenter, however, states that the proposed Super Emitter Program is not lawful. According to the commenter, Congress did not under the CAA to convey to the EPA the authority to delegate the monitoring of regulated facilities to third‐party members of the public for use by the EPA for compliance, supervision and enforcement. The commenter claims that, in effect, the EPA would be delegating to groups with unverified qualifications and technical expertise, according to the commenter an unprecedented action. The commenter claims that this provision of the proposed rules is also a violation of the separation of powers of the U.S. Constitution where the EPA is seeking to legislate and grant legal authority to itself to delegate regulatory authority to third‐party members of the public to monitor and report on regulated facilities, a legislative act that resides solely with Congress.

Other commenters similarly observe that the program as proposed would be the first time that the EPA has asserted authority under the CAA to create regulatory obligations for affected facilities based on monitoring conducted by unaffiliated third parties and without playing any role at all in verifying the information before imposing legal obligations on other private parties. In support of this unusual delegation of regulatory authority, these commenters asserted, the EPA characterizes the program as simply a BSER requiring monitoring and correction of unintentional releases, akin to LDAR, but evades the central concern that it is private parties—not the EPA, states, or regulated entities—who would be monitoring, notifying, and triggering the associated regulatory obligations.

Another commenter agrees with the EPA on the importance of identifying and addressing large emissions events. The commenter acknowledges that emissions from such events have the potential to be much greater than those from normal operations at a given facility and shares the EPA's interest in seeking to reduce the incidence of such large emissions events. However, like other commenters mentioned above, this commenter similarly observed that the proposed program was unique in that it would be the first time under the CAA that the EPA asserts authority to create regulatory obligations for affected facilities based on monitoring conducted by unaffiliated third parties. Claiming that the EPA did not explain the legal basis for establishing such a requirement, the commenter states that an explanation from the EPA is essential to understanding whether such a novel provision is legally viable.

Response: In light of the comments above and discussed elsewhere in this section regarding other aspects of the proposed Super Emitter Program, the EPA has made targeted revisions to the Super Emitter Program since the December 2022 Supplemental Proposal. The final Super Emitter Program, which the EPA is establishing pursuant to CAA sections 111 and 114(a), is based on the second proposed legal framework. First, as one commenter observes, the EPA has broad authority under CAA section 114(a) to accept and use third-party monitoring data for purposes related to CAA section 111, including better understanding the sources of large emitting events and assuring compliance with its regulations. CAA 111(a) authorizes the EPA to obtain any information necessary for the implementation of the CAA from any person “the EPA believes may have information necessary for the purposes of [implementing the CAA].” While the Super Emitter Program does not specifically require or request any third party to provide information on super-emitter events to the EPA, anyone can voluntarily provide such information to the EPA. It is the EPA's long-standing position that “information will be considered to have been provided . . . under section 114 of the Act . . . if its submission could have been required under section 114. . . .” 40 CFR 2.301(b)(2). Also, as discussed in detail in section X.C and further below, CAA 114(a) authorizes the EPA to require the owners and operators of the source of the super-emitter event to investigate and report the conclusions of that investigation to the EPA. As explained below, the final Super Emitter Program requires such actions from owners and operators upon their receipt of an EPA notice of a super-emitter event based on data submitted by EPA-certified third parties using EPA-approved technology. The EPA will send such notices only after having reviewed and deemed the data to be complete and accurate.

Second, for super-emitter events caused by regulated sources, the EPA has separate authority under CAA section 111 to ensure compliance with its regulations where a notification and subsequent investigation reveal noncompliance with those regulations. Much of the equipment likely to cause a super-emitter event is or will be subject to regulation under CAA section 111 ( i.e., NSPS OOOO, OOOOa, OOOOb, or state/Federal plans pursuant to EG OOOOc). For example, a super-emitter event might be caused by a regulated thief hatch that is open despite the EPA's requirement that thief hatches remain closed. In these cases, the Super Emitter Program serves an additional compliance assurance measure for the regulated equipment by notifying owners and operators of data demonstrating super-emitter events and requiring that they investigate and identify the source of the super-emitter event. Specifically, the Super Emitter Program serves as additional monitoring to inform and aid owners and operators in complying with the relevant NSPS or standards in state and Federal plans. Further, the EPA proposed and is finalizing the requirement under its fugitive emissions standards that where the source of the super-emitter event was a fugitive emissions component under NSPS OOOOb or a state or Federal Plan implementing EG OOOOc, the owner and operator must follow the repair requirements in the fugitive emissions work practice standards in NSPS OOOOb or the applicable state or Federal plan. As explained in the December 2022 Supplemental Proposal, the EPA considered this as part of the BSER for fugitive emissions at well sites and compressor stations.

In response to comments questioning the legality of allowing third party monitoring and notifications to directly trigger regulatory obligations, the EPA has revised the proposed program such that the EPA will play an essential oversight role in the final Super Emitter Program. Specifically, it will be the EPA, not third parties, that will notify owners and operators of super-emitter events after reviewing third-party notifications. Further, the EPA will only accept data submitted by EPA-certified third parties and collected using EPA-approved technologies. Upon receiving data submitted by a certified third party, the EPA will review the data for completeness and accuracy; the EPA will post such data and notify the identified owner or operator only after it has reviewed and deemed the information to be complete and accurate. Accordingly, the EPA plays a central role at every step: certifying (and de-certifying) the third parties who will be able to submit notifications under this program, approving the technology such parties may use, reviewing the notifications to ensure the information therein is accurate and complete, notifying owners and operators of such information, receiving and reviewing responses from owners and operators, and determining when to post information and responses publicly.

The final Super Emitter Program sets forth criteria that a third party must meet in order to be certified to submit data on super-emitter events to the EPA. These criteria ensure that the data submitted to the EPA are collected by a qualified third party with access to an EPA-approved technology and the technical expertise and capability to use such technology to detect and collect data on super-emitter events. The final rule also lists circumstances under which a third-party certification will be revoked, such as repeated submissions of data with significant errors, or engagement in an unlawful action ( e.g., trespass) when monitoring for super-emitter events.

Upon receiving data submitted by a certified third-party, the EPA will review the data for completeness and accuracy; the EPA will post such data and notify the identified owner or operator only after it has reviewed and deemed the information to be complete and accurate.

As finalized, the Super Emitter Program does not “delegate” any regulatory or enforcement role to third parties. Rather, the Super Emitter Program merely serves as a mechanism for the EPA to receive reliable data on super-emitter events from qualified third parties with access to and expertise in using EPA-approved advanced technology to detect super-emitter events. The Super Emitter Program also provides a structured process for the EPA to use that data to notify the owner or operator of a regulated facility of the existence of a super-emitter event that may indicate a lapse in compliance at the facility, or a source of fugitive emissions that this rule requires to be promptly repaired. There is no sense in which this framework “delegates” governmental authority of any kind to any third party. No action is required of an owner or operator solely on the basis of an action of a third party. In addition, the process by which the EPA receives data and issues notifications under the Super Emitter Program is separate from and unrelated to the EPA's enforcement functions.

This structure, where the EPA reviews and determines the reliability of reported data on super-emitter events, is similar to other, longstanding programs where citizens and other entities can report concerns about regulatory compliance to the Agency. For example, the EPA's Office of Enforcement and Compliance Assurance administers a program where citizens and other entities can report suspected environmental violations. See https://echo.epa.gov/report-environmental-violations#:~:text=Stop-,Stop,%2D800%2D424%2D8802 . The Super Emitter program likewise functions to allow third parties to share with the EPA monitoring data, and then allows the EPA to determine the reliability of the data, and engage with the relevant, regulated party to determine if there is a need for further action to ensure compliance with the EPA's regulations. The third parties reporting super-emitter events do not have an independent enforcement role as a function of the Super Emitter Program. Instead, the EPA retains its traditional enforcement authority.

As explained in the December 2022 Supplemental Proposal (87 FR 74752) and noted by one commenter, the Super Emitter Program serves as a backstop to addressing emissions from super-emitter events that were not prevented from other requirements in the rule. However, the EPA did not propose and does not require in the final program any specific investigation to be conducted to identify the source of the super-emitter event. Because the relevant investigations for identifying the source(s) of the super-emitter event may vary depending on what the third-party data reveals, the final rule defers to the owner and operator in deciding the appropriate investigation(s). However, where there are NSPS affected facilities (or designated facilities subject to a state or Federal plan implementing EG OOOOc) or associated equipment onsite, the owner and operator may conclude that they are unable to identify the source of the super-emitter event only after having conducted the applicable investigation listed in the final rule for such regulated source.

The EPA further notes that the obligation to investigate and report the source of super-emitter events (separate and apart from the obligation to take steps to address the super-emitting event) is not limited to NSPS affected facilities (or designated facilities subject to a state or Federal plan implementing EG OOOOc) and associated equipment; it also extends to other equipment onsite that an owner and operator suspects could be the source of a super-emitter event. As one commenter observes, the EPA has broad authority to require emissions reporting under CAA section 114(a). Among other things, CAA section 114(a) authorizes the EPA to require “any person who owns or operates any emission source” (except mobile sources) to provide information necessary for purposes of carrying out the CAA. In this case, section 114(a) authorizes the EPA to require the reporting of information on super-emitter events, so that the EPA may evaluate whether such large emissions can be adequately addressed under the EPA regulations to date or whether more needs to be done in the future ( e.g., during the next periodic review of the NSPS under CAA section 111). Therefore, the EPA expects the owner and operator to investigate all equipment onsite that they suspect could be the source of a super-emitter event, whether or not such equipment is subject to NSPS regulation or a state or Federal Plan implementing EG OOOOc. Where the super-emitter event was caused by equipment not subject to NSPS OOOO, OOOOa, or OOOOb, or a state or Federal plan implementing EG OOOOc, the owner and operator must report such finding. However, there is no requirement for the owner or operator to take action to eliminate or mitigate the emissions from the super-emitter event caused by sources not subject to an NSPS or a state or Federal plan implementing EG OOOOc.

While there are comments expressing concerns with the proposed program as described above, the EPA received comments expressing strong support for the program from several states, environmental groups and industry. One industry commenter concurs with the EPA on the importance of identifying and addressing large emissions events and shares the EPA's interest in seeking to reduce the incidence of such large emissions events. The commenter also agrees with the EPA that data transparency is valuable and shares the EPA's goal of disseminating information to mitigate emissions events. The EPA believes that the final Super Emitter Program, which has been significantly revised in response to comments, will serve its goal of reducing emissions from super-emitter events that were not prevented by other requirements in the rule.

2. Certification of Third Party

This section of this document presents a summary of significant comments received on certification of third-party notifiers as part of the Super Emitter Program and the EPA's response to those comments, as well as changes the EPA has made to the requirements since the December 2022 Supplemental Proposal.

The EPA received many comments regarding how advanced methane detection technology has been incorporated into our proposed standards, including the lack of clarity on which remote sensing technology would be considered for the program, how the remote sensing technology could be considered for the program, what an approval process could look like, and how best to make this program transparent.

Comment: Several commenters expressed concern with the lack of standard methods for the example technologies that the EPA identified in the proposed rule as compared to test method requirements ( i.e., validated test methods) that underpin compliance determinations for NSPS or national emissions standards for hazardous air pollutants (NESHAP) standards. One of these commenters suggested that the proposed programmatic requirements ( i.e., alternative test methods) be applied to the Super Emitter Program. Another of these commenters recommended that the EPA develop guidance on test and monitoring methods to use to define super-emitter emissions events.

Several commenters urged the EPA to not overly restrict the technologies that may qualify and suggested that the EPA should use the alternative test method approval process already under development to approve advanced methane detection technologies for monitoring fugitive components, covers, and closed vent systems in this rule for use in the Super Emitter Program. One of these commenters provided that such an approach could allow for additional technologies that could operate within the requirements of this program. Another commenter urged the EPA to use the already proposed alternative test method to remove any potential barriers on the third party to evaluate technology and to bring the measurement to the same level as that of the owner or operators while improving objectivity.

Some commenters raised safety concerns regarding individuals engaged in third-party monitoring. One of these commenters raised concerns that certain monitoring technologies used by third parties to identify super-emitter emissions events that need to be operated in the close vicinity of a site, and that individuals conducting that monitoring may not be aware of important safety concerns regarding that site. Another one of these commenters provided examples of such safety concerns associated with members of the public accessing sites without proper notice. For example, some sites can contain hydrogen sulfide (H₂ S), a gas that could result in serious health impacts for members of the public entering a site without proper protection. The commenters raised concerns that individuals may not be aware of such hazards or have the appropriate personal protection equipment (PPE) and training to mitigate them.

Response: Regarding the comments on the use of remote sensing technology and the lack of approved or validated methods for use in the Super Emitter Program, we agree with the commenters that the remote-measurement approaches used for this program should be evaluated in the same manner as any compliance measurement used in this rule. The EPA also agrees with the commenters' recommendations that we use the alternative test method approval process already under development to approve advanced methane detection technologies for monitoring fugitive components, covers, and closed vent systems in this rule. Therefore, in the final rule we are requiring that third parties participating in the Super Emitter Program use an alternative test method that has been approved under 40 CFR 60.5398b(d) of the final rule and we have revised the scope of the alternative test method program to now include the approvals for the Super Emitter Program.

Comment: Several commenters ask that the EPA clarify its intent as to which advanced methane detection technologies can be utilized for the Super Emitter Program. Several commenters maintained that the EPA must provide a clear pathway for communities and third parties to participate and engage in the Super Emitter Program. They also said that the EPA must ensure that data from approved monitoring technologies are accessible to all, including by allowing the use of OGI cameras in this program. These commenters urged the EPA to expand what they characterized as the overly restrictive technology standards proposed for the Super Emitter Program, which would currently work to limit the participation of NGOs and communities that lack access to remote detection technologies.

Response: In the December 2022 Supplemental Proposal, the EPA identified satellites, aircraft, and other mobile monitoring measurement systems that can quantify an emission rate of 100 kg/hr of methane or greater. These examples were intended to make clear that third parties would only use technology that could be used at a reasonably safe distance, well away from a well site, central tank battery, or compression station, to ensure the integrity of these sites and the safety of the individuals or organizations collecting the measurements. Nothing in this rule should be construed as authorizing third parties to enter well sites or any other affected facility or designated facility to take measurements. Also, we recognize that mobile monitoring platforms could be interpreted broadly; this language is the EPA's effort to account for the continuing advancement of methane detection technology, and the qualification to meet the mobile monitoring platform is that we would allow any un-fixed measurement technology operating offsite from a well site, central tank battery, or compression station that can quantify an emission rate of 100 kg/hr of methane or greater. For the final rule, the EPA is maintaining the proposed criteria regarding which measurement technologies can be used in the Super Emitter Program. While the minimum threshold remains 100 kg/hr, the EPA would consider the use of remote technologies with higher detection thresholds in this program. However, those technologies would be limited to reporting emissions events above their detection threshold.

Lastly, we acknowledge the desire of certain third-party groups to use OGI as part of this program. However, the current generation of this technology does not have the quantification ability required as part of this rule. More importantly, this technology cannot be operated at a distance and creates more potential for users getting too close to the site and creating risks to themselves or to the site. We recognize that a number of the technology vendors focusing on OGI are developing systems capable of quantification, and as these systems come online, this determination may change if there is a mechanism to ensure that the monitoring is only done at a reasonable and safe distance away from an applicable well site, central tank battery, or compression station.

The EPA further notes that direct monitoring is not the only way that communities can participate in or benefit from the Super Emitter Program. The EPA anticipates that a broad range of entities, including community organizations that are not themselves certified, might partner with a certified third party to identify locations of particular concern for monitoring attention. The EPA will also be posting the super-emitter event data shortly after it is received, which provides communities with information that could be relevant to local health and air quality, and could also be useful to communities seeking to advocate on their own behalf.

Comment: Several commenters raised concerns that the December 2022 Supplemental Proposal offered little clarity about the necessary demonstrated expertise for third parties. Many of these commenters also stated that the EPA should develop detailed criteria for the certification of these third-party notifiers. Furthermore, according to another commenter, the Agency should make transparent and publicly disclose what other qualified parties have been certified. Some commenters raised a concern that some third-party notifiers may be inadequately trained to detect methane leaks; these same commenters recommended that third-party notifiers be required to have appropriate training/certification to validate emissions events. Another commenter stated that a third party must complete an approval certification process by the EPA for inclusion in the Super Emitter Program; also this commenter suggested that third parties notify the EPA of planned monitoring, including submittal of a monitoring plan.

One commenter questioned how effectively a third party would be able to identify an owner or operator of a site or be able to contact the right people if the facility is covered by NSPS OOOOb. The same commenter mentioned the importance for notifications to be sent to the correct person at the operating company. Another commenter agreed that the qualifications of third-party reporters are important and that approved third-party reporters should show proficiency and accuracy in identifying super-emitter leaks.

Several commenters provided recommendations on how to improve the process for revoking certifications for third parties. A few of these commenters argue that the three-time threshold for inaccurate event notifications from a third party is too high and should not be limited to multiple notifications at the same facility owned by the same operator. Another commenter recommended that the criteria for revocation explicitly state that revocation would occur upon a third party's third submission of verifiably false data from any combination of operators or sites, or upon trespass or otherwise unlawful or unauthorized entry to a facility.

Response: The EPA agrees with the commenters that the final rule should more completely define the certification process and criteria these third parties must meet. Therefore, in the final rule we have amended the regulatory text to include the procedures an entity must follow when seeking certification, what information they must submit to the EPA as part of this certification process, and a set of standards an approved third-party notifier must continue to follow.

The final rule now provides direction for any entity requesting certification to be a third-party notifier to submit the required information to the Leader, Measurement Technology Group, Mail Drop: E143–02, 109 T.W. Alexander Drive, P.O. Box 12055, Research Triangle Park, NC 27711. The required submission information includes general information on the organization requesting the certification, qualifications for the certifying official, which measurement technologies will be used, standard operating procedures for data review, records management processes, and a Quality Management plan. The required information is not intended to be onerous, however these basic requirements are consistent with the EPA's internal data review process and are in place to ensure that notifications being provided to the EPA are actionable and accurate. We are also requiring third-party notifiers to maintain the relevant records from surveys conducted or sponsored by the third party, including data used to evaluate the validity of a super-emitter event but which is not required to be submitted as part of the notification.

In addition, the final rule defines the Administrator's authority to approve or disapprove certifications as a third-party notifier, clarifies when third parties must be certified, and provides greater detail on the process to revoke certifications. The EPA agrees with commenters' points that the program should be run transparently, and the identification of all certified third-party notifiers shall be posted on the EPA website at https://www.epa.gov/emc-third-party-approvals with a corresponding third-party notifier ID. The EPA disagrees with the comment that third parties must be recertified at a specific frequency; instead, the final rule requires third parties to amend their certification ( i.e., recertification) to account for any significant changes in their technology or other elements of their certification. The EPA considers it important to require third parties to amend their certification to account for the advancement in the methane detection technology and will structure the program to quickly evaluate these amendments.

Finally, the EPA agrees with the commenters that the Agency should expand the circumstances in which a third party can be removed from the list of approved notifiers. With the EPA's central role in handling super-emitter notifications, we have expanded the circumstances to include removal of a third party that has made material changes to their process without amending their certification, if a certified third-party notifier has repeatedly submitted data with significant errors, or if the third-party notifier engages in an illegal activity during the assessment of a super-emitter event ( e.g., trespassing). We are also finalizing the proposed provision that the Administrator revoke a certification upon receiving a petition from an owner or operator documenting that it has received three or more notices with materially erroneous information on a super-emitter event at the same well site, centralized production facility, or compressor station, submitted to the EPA by the same third-party notifier. Since the 2022 Supplemental Proposal, the EPA has improved the robustness of the Super Emitter Program by establishing specific and detailed criteria to ensure the qualifications of third parties who can be certified and the quality and accuracy of the data that the EPA will accept from the certified third parties; further, the EPA will review the submitted data for completeness and accuracy before issuing any notice of a super-emitter event to an identified owner or operator. The EPA believes that these safeguards will minimize, if not eliminate, issuance of clearly erroneous notices; however, there may be errors in the submitted information that cannot be readily discerned by the third-party notifier or the EPA, at least not without more time, which would undermine the Program's objective to provide owners and operators timely information to identify and address super-emitter events. In light of the above, the EPA believes that revoking a third-party's certification after three times of submitting data with material errors on the same facility is an appropriate balance between providing owners and operators timely notifications of super-emitter events at their facilities and minimizing the likelihood and therefore burden of owners and operators having to respond to notices with material erroneous information.

3. Notifications by the Third Party and Requirements

We received several comments on ways to improve the notification process in the Super Emitter Program. This section of this document presents a summary of significant comments received on the handling of notifications and the EPA's response to those comments, as well as changes the EPA has made to account for those comments, including a central role for the EPA in collecting and reviewing third-party reports of super-emitter events and providing notifications.

Comment: Several commenters expressed that super-emitter data should be published by the EPA and that the EPA should manage all data that is to be public and establish a protocol for when and what types of specific details of a potential super-emitter emissions event are published. Another commenter suggested that the EPA should maintain a public database of all super-emitter notifications by certified third-party reporters. Still another commenter strongly disagreed that the EPA should promptly make such reports available to the public online and recommended that the EPA should provide time to verify or authenticate the information from third parties and allow owners or operators to review and respond to the information.

Several commenters stated that notifiers should be required to provide proof of the event such as time, date, location, and visual evidence of leak origin. One commenter said that the EPA should show discretion in accepting information provided by third parties as proof that a super-emitter exists, including quantification of the super-emitter. Still other commenters were concerned that the notifications are based on a snapshot in time, which they asserted was not sufficient, and that the EPA should establish criteria for the third party to demonstrate that excessive rates of methane are occurring for an extended period of time.

Several commenters expressed concern that the December 2022 Supplemental Proposal did not state the amount of time required for notifications following the detection of a super-emitter. Many of these commenters discussed how the time required may be dependent on the type of remote sensing technology, the ability to identify the relevant operator, and the capabilities of the third-party notifier. In these individuals' comments, the commenters provided a range of potential suggested requirements for providing notifications, from 1 day to a few weeks. Some of these commenters identified that timely notification would lead to earlier mitigation, but more importantly that some of these super-emitter events are intermittent and investigation into their cause is more effectively performed closer to the event and would aid in prevention. An additional commenter raised concern that information received several months after a detection will likely be challenging for operators to utilize effectively.

Finally, one commenter suggested that third parties should attest that the notifier is an EPA-approved entity for providing the notification and that the information was collected and interpreted as described in the notification. The commenter went on to explain that a signed certification provides fidelity to the requirement that the information is coming from a verified source. The commenter believes that this can be in the form of a weblink that traces back to the EPA's website hosting the list of third-party notifiers.

Response: The EPA agrees that the program will be more effective with the EPA in a centralized role to accept and review third-party submittals and make the notifications to an owner or operator in a timely manner, and so we are revising the final rule to include a substantial oversight role for the EPA. The EPA also agrees with those commenters who assert that it is important that these data should be public, and to address these comments, the EPA is developing a Super Emitter Program Portal to be found at the following URL, https://www.epa.gov/super-emitter. The Portal will serve to manage the data associated with the Super Emitter Program, including data coming into the system from EPA-certified third parties, providing notifications from the EPA to affected owners or operators, responses back from the owner or operators, and display of the super-emitter data. This portal and the underlying data management system from which it is built will allow the EPA to quickly review incoming data for accuracy and completeness, allowing for timely notification of verified data to owner or operators.

The EPA does not agree with the commenters that verified data should not be public until such time that an owner or operator has a chance to review and respond to the information, and the EPA believes it is important that this program is operated transparently. However, the EPA is conscious of these commenters' concerns that many of the oil and gas basins are dense with sites and that uncertainty in the spatial resolution of some of the remote sensing platforms may make correct identification of the owner or operator challenging. Therefore, the EPA will not identify the attribution of the super-emitter source until the notified owner or operator of a site has the opportunity to respond; this will be further discussed later in this section.

The EPA agrees with those commenters that the third-party notifiers must be able to provide proof of a super-emitter event and therefore the final rule has defined the information that must be submitted by the third party into the Super Emitter Program Portal. Only those individuals and organizations that have been certified will be able to access the notification portion of the portal. The required information that must be supplied with the notification are the: third-party notifier ID; date of detection of the super-emitter event; location in latitude and longitude; owner, or operator of a well site within 50 meters of the identified latitude and longitude, if available; detection technology used; documentation ( e.g., imagery) of the super-emitter event and from which it is detected; quantified emission rate; and associated uncertainties. The EPA also agrees with those commenters that the EPA super-emitter data must be supplied in a timely manner and therefore in this final rule we are requiring that notifications must be supplied to the EPA within 15 days after the detection event; we believe this is a reasonable amount of time within which to acquire the data, verify the data, and identify an owner or operator, consistent with the importance of quick notification. In the final rule, to ensure that the EPA is providing actionable information to the owners or operators, the EPA will not review and/or provide any notifications to an owner or operator unless the third-party notification is received within 15 days after detection of the super-emitter event. Furthermore, the EPA agrees that a third party must attest to the accuracy of their notification and in the final rule we now include an attestation statement to be signed by the certifying official.

Information that is received within 15 days after detection and is attested, complete, and found to be accurate to a reasonable degree of certainty will be assigned a unique notification number, provided to the identified owner or operator as quickly as possible, and the notification will be made public at https://www.epa.gov/super-emitter at the same time. However, the initial public notification will not include the identity of the owner or operator, so that the notified owner or operator has an opportunity to respond before attribution is posted.

4. Requirements for Owners and Operators

We received several comments on the December 2022 Supplemental Proposal on the required actions when owners or operators receive notification of a super-emitter event as part of the Super Emitter Program. This section of this document presents a summary of significant comments received regarding the follow-up investigations, requirements for any necessary repairs, and reporting the results of those investigations to the EPA, and the EPA's response to those comments. This section also details changes the EPA has made in the final rule to account for those comments, changes in the final rule concerning the EPA's central role in handling responses from the owner or operator, and changes in the final rule reflective of this program as a compliance assurance program.

We received several comments supporting the requirement that owners or operators investigate the source and cause(s) of significant emissions events that are brought to an operator's or owner's attention. More than a few of these commenters took issue with our proposed use of “root cause analysis” for investigating potential causes of super-emitter events. Specifically, one comment argued that the concept of “root cause analysis” is embedded in numerous other regulatory and non-regulatory programs and has varied meaning and purpose in each application, and another commenter asserted that the phrase “root cause analysis” has connotations that lead to a much more involved process than the EPA appears to have envisioned in the December 2022 Supplemental Proposal. Many of these commenters suggest that “root cause analysis” be replaced by “investigative analysis,” broadly meaning the owner or operator must determine whether an emissions event has occurred and take steps to ensure that it will not happen again.

We received several comments discussing the suitability of the timelines provided in the December 2022 Supplemental Proposal. Several commenters indicated the proposed 5 days to initiate root cause and 10 days to complete corrective action are inadequate, as some locations are remote in nature or, in some instances, may require longer timeframes to obtain equipment or schedule service companies to complete the corrective action. Some of these commenters recommended that the EPA provide owners or operators with 14 business days to conduct an analysis of the incident and provide the EPA with recommended actions to avoid future occurrences; one commenter also suggested that if analysis cannot be conducted within 14 business days, the owner or operator should notify the EPA and let the Agency know when the analysis will be available, which in no event may exceed 90 days.

The EPA also received several comments regarding the potential causes for super-emitters and what the appropriate steps should be for investigating super-emitter events. One commenter reasoned that many of the super-emitter events of this magnitude are caused by unlit flares and tank malfunctions and that in those cases owners and operators should be able to fix the underlying issue quickly. Another commenter identified that super-emitter emissions may be caused by an anticipated, short-duration event such as operations and maintenance activity at the site. Several commenters raised that for sites with validated continuous monitoring systems, these systems will very likely already have noted and mitigated super-emitter events before even receiving a notification.

Regarding whom is subject to the Super Emitter Program, the EPA received some comments that no investigative analysis should be required if the emissions are not associated with an affected facility under NSPS OOOOb. Another commenter contends that the EPA has broad authority under CAA section 114 to accept and use third-party monitoring data for purposes related to CAA section 111, including ensuring compliance.

The EPA received several comments on how best to manage super-emitter event reporting after receipt of a super-emitter notification. A commenter explores the possibility that an owner or operator should only be reporting to the EPA when the facility owner or operator confirms the super-emitter event; this commenter also discussed the EPA's developing a document repository for the notices to operators it receives as well as the reports sent by the owners and operators in response. A few commenters representing state and Tribal authorities request that all subsequent reports and submittals should also be copied to the state, to aid states' compliance efforts under the Super Emitter Program and to provide information that states can use in their own compliance and enforcement efforts. Several commenters raised concerns regarding either the misidentification of an operator's facility or inaccurate quantification of super-emitter emissions. Another commenter requested that we maintain the language referenced in the December 2022 Supplemental Proposal preamble to allow that owners and operators would have the opportunity to rebut any information in a notification provided by the qualified third parties in their written report to the EPA, by explaining where appropriate that: there was a demonstrable error in the third-party notification; the emissions event did not occur at a regulated facility; or the emissions event was not the result of malfunctions or abnormal operation that could be mitigated.

The EPA is finalizing the Super Emitter Program as primarily a compliance assurance program and is not maintaining the root cause analysis and corrective action requirements from the December 2022 Supplemental Proposal. The EPA acknowledges the commenters' concern with the use of the ambiguous root cause and corrective action language for this sector and is in the final rule defining a set of investigations that an owner or operator must perform when provided with a super-emitter notification. The EPA is maintaining the requirement from the supplemental proposal that the owner or operator of a well site, centralized production facility, or compressor station must initiate an investigation within 5 calendar days after a notification, and based on comment we are extending the period to conduct the investigation to 15 calendar days. These time periods are appropriate given the very large emissions associated with super-emitter events; it is important that owners and operators respond quickly to these very large emissions events and take immediate action to stop them. Many operators have noted to the EPA that prompt notice of super-emitter events is important to them exactly for this reason.

The EPA has defined a series of required investigations in the final rule, designed to target these very large emissions events as part of a compliance assurance program. In response to comments, the investigations are designed to minimize the time and resources associated with conducting these investigations. Upon receiving a super-emitter notification by the EPA, a recipient is first required to determine if it is the owner or operator a well site, centralized production facility, or compressor station within a radius of 50 meters from the latitude and longitude provided in the notification, and if not, the recipient's investigation is complete. If the recipient does own a well site, centralized production facility, or compressor station within a 50-meter radius, it must determine the applicability of any equipment under 40 CFR part 60, subpart OOOO, OOOOa, or OOOOb, and/or a state or Federal Plan implementing subpart OOOOc, and is required to perform the investigations as defined in that applicable subpart. However, for ease of use, the investigations in each of these subparts are identical. We agree with the commenters that the largest potential for super-emitters is from maintenance events and failure of controls and, as such, have incorporated elements into the investigations under the requirements for maintenance and controls to identify potential causes. Specifically, the investigation incorporates the review of any maintenance events ( e.g., liquid unloading) conducted from the date of detection until the start date of the investigations; and the review of process monitoring data ( e.g., SCADA systems) from control devices to identify any potential causes of a super-emitter event. We also agree with the commenters that methane monitoring surveys and/or continuous emissions monitoring conducted from the date of detection until the start date of the investigations would have identified the presence or absence of a super-emitter event and when an event is identified the owner or operator could quickly identify the cause(s). All these investigations are designed to leverage actions potentially being performed or recorded as part of daily operation of a site and are effective tools for identifying large emissions events. The EPA also recognizes that all sites will not have continuous monitoring systems and that the owner or operator is likely not to have conducted fugitive monitoring between the date of detection and the notification; in those events we are requiring the owner or operator to conduct screening for a super-emitter event using either OGI, EPA Method 21, or an approved alternative test method(s) approved per 40 CFR 60.5398(d).

The EPA has restructured the reporting requirements for owners and operators in the final rule to be consistent with the change in the program to focus on compliance assurance and to account for the revised investigation requirements in the rule. While some commenters suggested that only confirmed super-emitter events should require reports, it is important for an owner or operator to report the results of their investigation in any case, as the absence of a super-emitter event is equally as important as the confirmation for the EPA, the state, local, or Tribal authority, and the general public. As such, we are requiring any owner or operator who receives a notification to report the finding of their investigation. The EPA agrees with these comments requesting that these owner or operator super-emitter reports be readily accessible, so the EPA is requiring that these reports be submitted through the Super Emitter Program Portal to aid in the public display of data. The EPA also agrees with those state and Tribal authorities that super-emitter reports should be available to the states at the time of reporting, and the Super Emitter Program Portal will include a function to notify a state, local, or Tribal authority when notifications and/or reports from their jurisdiction are received. The EPA is requiring that owners or operators report the findings within 15 days after receiving a notification of a super-emitter event; this marks the final day of the investigation period and is a timeline that is consistent with criteria in the December 2022 Supplemental Proposal for reporting initial corrective action. We acknowledge that we received comment from industry requesting longer timelines for corrective actions. Due to the large size of these emission events, the EPA considers the 15 days requirements a reasonable timeframe within which to conduct and report the required investigations to determine if the emission event is ongoing is consistent with the objective of this program to provide actionable information to owners or operators of facilities experiencing large emissions events, so they can investigate and perform repair if needed. The super-emitter program does not place any additional requirements or timeline to repair ( i.e., corrective actions) the source of these large emission events that are not already included in the rule, however the final rule does include reporting requirements if the emission events are ongoing at the time of the initial report submittal.

The level of reporting required by the owner or operator is dependent on the results of the investigation and the super-emitter event. The owner or operator of a site within 50 meters from the latitude and longitude in the notification is required to provide the super-emitter event notification ID, general identification of the facility, whether the equipment on the site is subject to regulation under the applicable subpart, and whether you were able to identify the super-emitter event. If the owner or operator is able to identify a super-emitter event, the owner or operator would also report if the equipment was subject to an applicable regulation (including the applicable subpart), whether or not the super-emitter event is ongoing at the time of reporting, and, if the super-emitter event is not ongoing at the time of reporting, the actual or estimated date and time when the event ended. If the super-emitter event is ongoing at the time of reporting, the owner or operator would provide a short narrative of the plan to end the super-emitter event, including an expected end date of the event, and the owner or operator would be required to update the initial report within 5 days after the actual end date of the super-emitter event.

Finally, we acknowledge the commenters' concerns that a third party may either misidentify a site's owner or operator or provide inaccurate data, and we agree with the commenters that owners and operators should have the opportunity to refute the information provided by the third party. The revised program in this final rule will give the owner or operator the opportunity to respond before the emissions event is attributed to a particular owner or operator, through posting of the report that the owner or operator submits to the EPA though the Super Emitter Portal.

5. Recordkeeping and Reporting Requirements for Process Controllers Not Included in the Affected Source

Comment: Commenters pointed out that 40 CFR 60.5420b(b)(7) requires owners and operators to submit an identification of all process controllers that are not powered by natural gas in the initial annual report, and such controllers are not covered by the definition of the affected facility for process controllers for NSPS OOOOb. The commenters recommended that owners or operators only be required to maintain records and submit information sufficient to determine compliance with the regulations. The commenters contend that having requirements for equipment that is not part of an affected facility exceeds the EPA's authority granted under CAA section 111 and add that there is no environmental benefit to keeping or submitting information for equipment that cannot have emissions. The commenters recommended that the EPA delete any reporting or recordkeeping requirements for these controllers from the final regulations.

Response: After considering this comment, we have determined that it is appropriate in this instance to require identification of the equipment that is included in the affected facility, rather than the equipment that is not part of the affected facility. The process controllers included in the affected facility are those that are subject to the emissions standards, whereas process controllers not included in the affected facility are not subject to the emissions standards in the final rule and also mostly have no potential to emit methane or VOCs. Therefore, we have revised the recordkeeping requirements to require identification only of controllers that meet the finalized definition of an affected facility, which are those process controllers that are driven by natural gas and that are not ESDs.

D. Process Controllers

Process controllers are among the largest sources of methane and VOC emissions in the source category. In the December 2022 Supplemental Proposal, the EPA proposed for both the NSPS OOOOb and EG OOOOc to define the process controller affected facility, and designated facility, as the collection of all natural gas-driven process controllers at a site. The December 2022 Supplemental Proposal, like the November 2021 Proposal, proposed two different standards for process controllers. For affected facilities that are not located in Alaska, the EPA proposed a zero-emissions standard and explained that it could be achieved with any one of several available technology options that many owners and operators are already deploying to varying degrees, including the use of electric controllers or compressed air systems (powered by the grid or by an onsite generator), solar-powered controllers, and natural gas-driven controllers that are self-contained or that are routed to a process. For affected facilities that are located in Alaska and do not have access to grid power, the EPA proposed a low-bleed emissions standard for continuous vent process controllers and a requirement that intermittent process controllers be periodically monitored for leaks and malfunctions using OGI.

A number of comments were received on aspects of the proposed NSPS OOOOb and EG OOOOc zero-emissions standard. This included comments on the costs and emissions estimates that supported the BSER analysis. These comments and the EPA responses are provided in section XI.D.1 of this document. The EPA received other comments related to the zero-emissions standard, including comments regarding access to reliable electricity and the technical feasibility of solar-powered controllers, routing emissions from natural-gas driven controllers to a control device, the potential impacts on small businesses, and the secondary emissions from the use of onsite generators. These comments and the EPA's responses are provided in section XI.D.2 of this document. Section XI.D.3 summarizes the refreshed BSER analysis and conclusions for the final rule. Comments were received regarding the compliance dates for both the NSPS and the EG. These comments and the EPA's responses are provided in section XI.D.4 of this document. The EPA also received comments regarding proposed recordkeeping and reporting requirements for process controllers not included in the affected facility and the criteria that would determine whether a process controller was modified or reconstructed. These comments, along with the EPA responses and the resulting rule changes, are provided in sections XI.D.5 and D.6 of this document. The EPA's full response to comments on the November 2021 Proposal and December 2022 Supplemental Proposal, including any comments not discussed in this preamble, can be found in the EPA's RTC document for the final rule.

In addition to the changes made to the final NSPS and EG to address these comments, one other change in terminology was made to address confusion in comments related to the types of equipment that may be used to perform the functions of process controllers. That change is discussed in section XI.D.7 of this document.

1. BSER Cost Analysis

As described in the December 2022 Supplemental Proposal, the EPA reviewed a range of technologies (control options) for limiting or avoiding GHG (methane) and VOC emissions from process controllers. The EPA concluded that adequately demonstrated zero-emissions pneumatic controller systems were available throughout the production and the transmission and storage segments. To evaluate the costs of these systems, the BSER analysis for the December 2022 Supplemental Proposal was performed for three model plant sizes in both the production and the transmission and storage segments. These model plant sizes were based on the number of natural gas-driven pneumatic controllers at a site: 4 controllers for the “small” model plant, 8 controllers for the “medium model plant,” and 20 controllers for the “large” model plant. For new sources, these controllers were broken down by low-bleed and intermittent vent. For existing sources, there was also one high-bleed controller for each model plant size. The zero-emissions options analyzed for each model plant were: electric controllers powered by the grid, electric controllers powered by solar energy, compressed air systems powered by the grid, and compressed air systems powered by an onsite generator. As a result, the EPA's cost analysis considered sites both with and without electrical service (grid power). Based on this analysis, the EPA concluded that there was at least one option for each model plant size with a cost effectiveness value that is within the range the EPA considers to be reasonable for the purposes of this rulemaking.

The EPA received and considered comments that resulted in updates to its cost analysis. These updates focused on model plants as well as the capital recovery periods for several options, and the option of using a generator to power electric controllers at sites without grid electricity was added. Each of these issues is discussed in more detail below.

Comment: One commenter recommended that the EPA gather additional information to create a representative gathering and boosting compressor station model plant. They indicated that gathering and boosting compressor stations typically have many more than 20 controllers and require air compressors larger than 20 horsepower, as the EPA assumed in the “Large Model Plant” for production sites. Another commenter indicated that some multi-well sites, central production facilities, and compressor stations may contain 100–200 controllers.

One commenter indicated that the EPA's small, medium, and large model plants do not reflect the actual average size of transmission and storage facilities based on the average size reported in EPA's GHGI, and that the EPA should increase the size of its model plants to accurately reflect average plant sizes.

A commenter noted that intermittent controllers represent most of the pneumatic devices in operation within the petroleum and natural gas system segments today.

Response: In response to these comments, the EPA made the following updates to the controller model plants.

• Two new “midstream” model plants were added to represent gathering and boosting stations. The small midstream model plant contains 20 pneumatic controllers, and the large midstream model plant contains 100 pneumatic controllers.
• The three transmission and storage model plants used in the supplemental analysis were replaced by a small transmission and storage model plant (30 pneumatic controllers) and a large transmission and storage model plant (50 pneumatic controllers).
• The breakdown of controllers at the new small production model plants was updated to reflect a higher percentage of intermittent vent controllers. For new sources, the supplemental analysis assumed two low bleed and two intermittent vent controllers. This was updated to one low bleed and three intermittent vent controllers.

Comment: One commenter pointed out that for electric-powered compressed air systems, the EPA applied an annualization period of 15 years as opposed to the 6-year period in the 2021 Carbon Limits study.

Response: The EPA agrees with the commenter that, while the EPA correctly applied the cost estimates from the 2021 Carbon Limits study, the EPA incorrectly applied an annualization period of 15 years instead of the 6-year period in the Carbon Limits cost estimates. This realization caused the EPA to review all the capital recovery annualization periods for the zero-emissions options. This led to the following updates for the capital recovery annualization periods in the analysis.

• For electric controllers powered by the grid, from 15 years to 6 years.
• For solar-powered electric controllers, from 15 years to 10 years.
• For instrument air systems powered either by the grid or from generator from 15 to 6 years.

Comment: Commenters submitted information to support the EPA's understanding that zero-emitting options for process controllers are technologically and economically reasonable. As a result of comments submitted in response to the December 2022 Supplemental Proposal, the EPA engaged in a clarification discussion with EQT regarding its process controller replacement program. The EPA learned that EQT Corporation, one of the largest producers of natural gas in the U.S., successfully implemented a program to replace over 8,000 natural gas-driven controllers at their sites. EQT announced the replacement initiative in June 2021, and has completed the project. While EQT explored a variety of zero-emitting options, the option they found most effective was the use of generators to power electric controllers.

Response: Although the EPA evaluated the use of generators to power compressed air systems for process controllers at sites without grid electricity, the EPA did not consider the use of generators to power electric controllers at sites without grid electricity in the December 2022 Supplemental Proposal. Using available information, the EPA estimated costs for systems using electric controllers powered by a generator. The EPA estimates the capital costs for these types of systems to range from just under $29,000 for the smallest production model plant to over $350,000 for the largest midstream model plant and the annual costs to range from around $8,500 for the smallest production model plant to over $55,000 for the largest midstream model plant. For summary information on the cost effectiveness of the analyzed available control options, see tables 18 and 19. For more complete information on the cost analyses conducted for process controllers, see the TSD for the final rule.

2. Zero-Emissions Standard

Comment: Several commenters remarked that it would be difficult for some sites to comply with the zero-emissions standard for process controllers due to a lack of access to electrical power at rural locations. Several commenters noted that sites are sometimes miles away from the existing electrical grid, and others mentioned that there can be challenges to connecting to a nearby grid, such as with right-of-way issues for placement of power lines.

Response: The commenters appear to suggest that the zero-emissions standard is only feasible if electrical grid power is available to sites. The EPA disagrees that grid power is necessary to comply with the zero-emissions standard for process controllers. The zero-emissions standard is technology-neutral and does not require that energy from the electrical grid be used to power controllers. There are many other technologically feasible and cost-effective options that are available to owners or operators to achieve zero emissions from process controllers, including self-contained controllers, solar-powered controllers, controllers powered by electric generators, and controllers that have their emissions routed to a process. As noted here, these options that are not powered by electricity from the commercial power grid are cost-reasonable. These options are discussed further in the December 2022 Supplemental Proposal (87 FR 74763).

Comment: The December 2022 Supplemental Proposal included discussion of the technical viability of solar-powered process controllers. While many commenters on the November 2021 Proposal expressed the opinion that solar-powered process controllers were not a viable option due to perceived technical limitations, one commenter cited a study by Carbon Limits that demonstrated solar-powered controls installed at well sites in remote and cold locations such as Northern Alberta and British Colombia have been proven to operate properly without major reliability issues. Several commenters on the December 2022 Supplemental proposal continued to state that solar-powered process controllers would not be feasible in some situations and specifically addressed the EPA's reliance on the Carbon Limits report. For example, one commenter indicated that the Carbon Limits report focuses on the reliability of solar power systems in colder climates, not areas with limited sun exposure. As a result, the commenter points out, the Carbon Limits study does not address the reliability of solar-powered systems in areas with limited sun exposure, such as West Virginia, or in canyons and mountain valleys. Commenters also noted that other factors limit the feasibility of including solar-powered systems at sites that have significant numbers of foggy or cloudy days, or high amounts of ice or snowfall, and in cold locations where battery storage could be negatively impacted. The commenters state that reliance on solar power leaves sites subject to the weather and possibly effectively shut down for days. One commenter noted that solar power may not be feasible for gathering and boosting operations, which have larger footprints and substantially greater power needs than other types of operations.

Response: Some commenters contend that solar power is not a feasible option to use for controllers at some sites because of perceived technical limitations. Considering that the electrical power needed by each controller is relatively low, the EPA reasonably expects that a solar power system can be sized with the appropriate number of panels and batteries to power process controllers at most, if not all, sites. The EPA does not agree with commenters' claim that powering process controllers with solar power is technically infeasible. The EPA has examined these claims from commenters and finds that solar technology has advanced such that it has overcome previous technical limitations and is now a technically viable control option. Further, the use of solar power is not required by this rule. Another control option determined to be cost-effective at all sites, based on the EPA's BSER analysis, is the use of a generator to power electric process controllers, and the use of a generator to power a compressed air system was cost-effective at larger sites. Other options available to meet the zero-emissions standard at sites without grid power and without using solar power include self-contained process controllers, or routing emissions from controllers to a process, although costs were not evaluated for these two options.

Regarding the suggestion that compliance with the zero-emissions standard is infeasible at sites requiring a large electricity demand because solar power would not adequately supply this amount of power, we note that most gathering and boosting stations and transmission and storage sites already have electrical grid power at the site. However, as evidenced by the tables below in this section that summarize the cost analyses, sites that are not connected to the grid have one or more cost-effective alternatives other than using solar power (using a generator to power electric controllers or a compressed air system), and the owner/operator is able to choose their preferred compliance option for each site.

Comment: Several commenters requested that the EPA allow owners or operators to route emissions from process controllers to a control device that achieves 95 percent control. The commenters report that this would be a cost-effective emissions reduction method for the many sites that have control devices onsite already. Other commenters remark that they are already routing emissions from process controllers to control devices and that requiring a zero-emissions standard for units already controlled by 95 percent or more requires the same capital and annual investment, but with little additional emission reduction over the baseline.

Response: We evaluated the use of control devices achieving 95 percent pollution control in our analyses for the December 2022 Supplemental Proposal. This control option was determined not to be the BSER for new or existing sources and was not used to develop the process controller standards for the NSPS or the presumptive standards in the EG. Zero emissions from new and existing process controllers was shown in our analyses to be technically achievable through several available options, including the use of self-contained controllers, electrical controllers powered by electricity from the grid or solar power systems, or controllers powered by compressed air using electricity from the grid or from electric generators, and by routing emissions to a process. The EPA has also shown that at least some of these available options are cost-effective for different types of facilities (model plants). Since these options achieve a rate of zero GHG (methane) and VOC emissions, compared to an emission rate of up to 5 percent of the baseline emissions through the use of a control device, we have not changed our determination that a zero-emissions option is the BSER. The baseline that the EPA used for the BSER analysis did not assume that emissions from the collection of process controllers was already being controlled at a 95 percent reduction because EPA does not have information indicating that any sizable portion of the industry is already being controlled at that level. While the EPA acknowledges that some process controllers may be subject to state-level regulations that result in such controls (95 percent reduction compared to uncontrolled emissions), the EPA does not have information indicating how prevalent such controls are for existing sources and therefore could not reasonably assume that such level of control reflected an accurate representation of a typical industry source, or even a typical source in a particular state or geographic region. While some state regulations may include a provision that could require certain process controllers to reduce emissions by 95 percent or more, those same regulations also include various exemptions, variances, and applicability thresholds that make it unclear which sources are actually achieving the 95 percent reductions. The EPA did not have sufficient information on this issue to alter the BSER analysis. The Agency was not presented with data or any empirical evidence to show how many, or which, sources are currently being controlled to this extent. The Agency was not compelled to alter the BSER analysis because of the anecdotal accounts provided by commenters. However, when developing state plans for the implementation of the EG for existing sources, states have the ability through RULOF to apply a less stringent standard with an appropriate demonstration in accordance with the requirements of 40 CFR part 60, subpart Ba.

Comment: Several commenters request that the EPA consider allowing the use of low-bleed or intermittent-bleed pneumatic controllers at low production/small sites. The commenters noted that some older facilities currently have very little throughput, and therefore low emissions from pneumatics due to infrequent activation. They also noted that low-producing wells could be close to the end of their production cycle life and may only contain a limited number of controllers. The commenters add that the complete retrofit of a low-producing facility is likely cost-prohibitive based on well economics and could result in many low production wells or stripper well sites shutting in production.

Response: As demonstrated in analyses conducted for the December 2022 Supplemental Proposal and the refreshed analysis conducted for the final rule (see section XI.D.3 below), we found zero-emissions options to be cost-effective even at small sites ( i.e., four process controllers at the site in our smallest model plant scenario). The emission factors used in the analyses are average emission factors, which are based on emissions from many sites with varying actuation frequencies. There is considerable evidence that malfunctioning natural gas-driven intermittent vent controllers are a significant source of emissions and the emissions from an intermittent controller that is malfunctioning and venting continuously are not related to the actuation frequency. While sites with controllers that actuate infrequently may have lower than the average emissions, the cost effectiveness values for at least some zero-emissions control options ( i.e., electric controllers powered by the grid, by solar power, and by power created by an onsite generator) are comfortably within the range that the EPA considers to be acceptable (see 87 FR 74762), such that even if emissions were less than one-quarter of the average (which the EPA can reasonably expect to be rare), the EPA would still consider the costs acceptable given the emissions reductions that would be achieved.

Further, while the emissions from natural gas-driven pneumatic controllers at a small site may be low in comparison to those from a central production facility or gathering and boosting station, the sheer number of small sites means that the cumulative methane emissions from these sites are significant. The EPA estimates that 47 percent of the total nationwide emissions from pneumatic controllers occurs from sites with less than four controllers. In a study funded by DOE's National Energy Technology Laboratory (DOE–NETL), GSI Environmental Inc. (2022) estimates that marginal natural gas and oil wells account for 59 percent and 37 percent of cumulative methane emissions from oil and natural gas production, respectively, and roughly half of cumulative methane emissions from combined oil and natural gas production. Similarly, Omara, et al. (2022), estimate that low production well sites account for roughly half (37–75 percent) of all oil and natural gas well site methane emissions. When considering the costs of the various control options in conjunction with the associated emission reduction of those same control options, the EPA found even for sites with relatively few process controllers, it was cost-effective to achieve a zero-emissions standard. For additional discussion of marginal wells, see chapter 6 of the Final Rule TSD. Lastly, when developing state plans for the implementation of the EG for existing sources, states have the ability through RULOF to apply a less stringent standard with an appropriate demonstration in accordance with the requirements of 40 CFR part 60, subpart Ba.

Comment: Several commenters are concerned about the secondary emissions that will be created if natural gas-fired generators are used to power process controllers. The commenters are concerned that the operation of generators could result in increased cumulative nitrogen oxide (NO_X) and VOC emissions as well as criteria pollutants and hazardous air pollutants (HAP). The commenters indicated that these emissions could potentially offset the emissions reductions from the methane and VOC, and these emissions from sites in ozone non-attainment areas could prevent those areas from gaining ozone attainment status.

Response: The EPA recognizes that if owners and operators elect to comply by installing and operating a generator, there will be secondary emissions generated from the fuel combustion; however, we have estimated the emissions that would be created by generators and found that they are far outweighed by the VOC and GHG (methane) emissions reduction that would be achieved by using process controllers that are not driven by natural gas. For the December 2022 Supplemental Proposal, while we did recognize that a commenter had provided estimates of these emissions, we did not separately analyze the secondary emissions that would be created if a generator was used to power this equipment.

We have now conducted that analysis and estimate that for a natural gas-fired generator to power this equipment, the secondary criteria pollutant emissions would be 43 pounds per year (lb/yr) CO, 306 lb/yr NO₂, 6 lb/yr PM, and 3 lb/yr PM_2.5 for a 5 HP compressor and 172 lb/yr CO, 1,222 lb/yr NO₂, 26 lb/yr PM, and 13 lb/yr PM_2.5, for a 20 HP compressor. The secondary GHG emissions generated as a result of this electricity generation are estimated to be 11,654 lb/yr CO₂, 0.2 lb/yr methane, and 0.02 lb/yr N₂ O for a 5 HP compressor and 46,618 lb/yr CO₂, 0.9 lb/yr methane, and 0.09 lb/yr N₂ O for a 20 HP compressor. Considering the global warming potential of these GHGs, the total CO₂ Eq. emissions would be 11,667 lb/yr CO₂ Eq. from a 5 HP compressor and 46,666 lb/yr CO₂ Eq. from a 20 HP compressor. With the total CO₂ Eq. emissions from process controllers at a small site estimated to be 303,000 lb/yr and 7.5 million lb/yr for a large site, the total CO₂ Eq. reduction from the use of zero-emissions process controllers powered by a generator running a compressed air system would be more than 95 percent when compared to the uncontrolled methane emissions from natural gas-driven controllers. No other secondary impacts are expected. Considering this information regarding secondary emissions, we continue to find that the BSER for reducing methane and VOC emissions from natural gas-driven controllers in the production and the transmission and storage segments of the industry to be the use of controllers that have methane and VOC emission rates of zero.

3. Final BSER Conclusions

Based on the updates discussed above in section XI.D.2, the EPA refreshed the BSER cost analysis for new sources. This analysis estimates the cost and emission reductions for the following zero-emissions options. For sites with access to electricity, the zero-emissions options include electric controllers and pneumatic controllers powered by compressed air systems. For sites without access to electricity, the zero-emissions options include solar-powered electric controllers, electric controllers powered by a generator, and pneumatic controllers driven by a compressed air system powered by an onsite generator. The results of these updated analyses are shown in table 18. For more detailed information on these cost estimates, see the TSD for the final rule.

For new sources, the EPA finds that all the options identified in table 18 are adequately demonstrated options for use of process controllers that are not driven by natural gas, thus resulting in zero GHG and VOC emissions. For overall cost effectiveness to be considered reasonable for new sources, either the cost effectiveness of GHG (methane) or VOC on a single-pollutant basis must be within the ranges considered reasonable by the EPA or the cost effectiveness of both methane and VOC on a multipollutant basis must be within the ranges considered reasonable by the EPA. As shown in table 18, for every model plant in all sectors, there are two or more options for new sources for which the cost effectiveness is considered reasonable by the EPA. This is true for sites with electricity from the grid, as well as sites without this electrical service. For example, for a medium sized model plant in the transmission and storage segment at sites without access to grid electricity, the single-pollutant cost effectiveness values for solar-powered electric controllers are $435 per ton of methane and $1,566 per ton of VOC, and the single-pollutant cost effectiveness values for electric controllers powered by a generator are $1,327 per ton of methane and $4,775 per ton of VOC. All of these values are within the range that the EPA considers to be reasonable. For a compressed air system powered by a generator for this model plant, the single pollutant values are $2,725 per ton of methane and $9,804 per ton of VOC. While these values exceed the levels typically considered reasonable by the EPA, the multipollutant cost effectiveness values of $1,363 per ton of methane and $4,902 per ton of VOC are within the ranges considered reasonable by the EPA. Therefore, the EPA considers the costs of all three zero-emissions options for this model plant to be reasonable given the associated 100 percent emission reduction achieved.

As discussed above in section XI.D.2, some commenters contend that solar-powered controller systems are not a technically feasible emission control option. The EPA disagrees with this comment, as the successful use of solar-powered controllers has been demonstrated. The EPA accepts that there may be certain situations where site-specific conditions may not be favorable to the use of solar-powered controller systems. However, this analysis shows that there are other demonstrated options available for all model plant sizes at sites without electricity with costs that are considered reasonable given the resulting methane and VOC emission reductions. In addition, while information was not available to fully analyze the costs, the option of collecting the emissions from natural gas-driven pneumatic controllers and routing them to a process and the option of self-contained natural gas-driven pneumatic controllers also achieve 100 percent emission reductions. Therefore, they are considered equivalent to the use of controllers not driven by natural gas.

The options evaluated for sites without grid electricity include the use of a generator to power either electric controllers or an instrument air (compressed air) system. As pointed out by some commenters, the use of these generators will create secondary air pollution. As discussed in more detail above in section XI.D.2, on an individual site basis the EPA concludes that the emissions that would be created by generators are far outweighed by the methane and VOC emissions reduction that would be achieved by using process controllers that are not driven by natural gas.

In conclusion, based on comments received, the EPA refreshed the BSER analysis with respect to costs and the associated emissions reductions. The EPA also considered other comments on the BSER analysis and the proposed zero-emissions standard for process controllers. After this consideration, the EPA continued to conclude that BSER for new process controllers is the use of zero-emissions process controllers that do not emit GHG (methane) or VOC to the atmosphere. Therefore, the final rule maintains the proposed zero-emissions standard.

The EPA also refreshed the BSER analysis for existing sources. For each zero-emissions option, the foundation for the cost estimates for existing sources was the same as for new sources. However, adjustments were made to account for differences in the costs that would be incurred for existing sources. For example, the installation costs were assumed to be twice as high for existing sources as compared to new sources. Another difference between the new and existing source analysis is related to the types of controllers assumed to be onsite for purposes of the model plants utilized in the analysis. The new source model plants did not include any high-bleed controllers. For existing sources, it was assumed that there was one high-bleed controller at every model plant. Thus, the baseline emissions, and the resulting emission reductions, were greater for existing sources as compared to new sources. The same zero-emissions options were evaluated for existing sources as for new sources, and, as for new sources, the EPA finds that all the options identified are adequately demonstrated options for use of process controllers that are not driven by natural gas, thus resulting in zero GHG (methane) emissions. The results of the refreshed cost analysis for existing sources is provided in table 19.

As shown in table 19, for every model plant in all sectors, there are two or more options for which the cost effectiveness for methane for existing sources is considered reasonable by the EPA. This is true for sites with electricity from the grid, as well as sites without this electrical service. For example, for the small model plant in the transmission and storage segment at sites without access to electricity, the cost effectiveness values ($ per ton of methane) are $564, $1,493, and $2,797 for solar-powered electric controllers, electric controllers powered by a generator, and compressed air powered by a generator, respectively. While the cost effectiveness for compressed air powered by a generator is above the level typically considered reasonable by the EPA, the other two options are well below the levels considered reasonable. The discussion above related to technical feasibility of solar-powered controllers and secondary emissions from generators for new sources is equally applicable for existing sources. As for new sources, routing pneumatic controller emissions to a process and using self-contained natural gas-driven pneumatic controllers are other control options available to achieve a zero-emissions standard.

In conclusion, based on comments received, the EPA refreshed the BSER cost analysis for existing sources. The EPA also considered other comments on the BSER analysis and the proposed zero-emissions presumptive standard for process controllers. After this consideration, the EPA continues to conclude that BSER for existing process controllers is the use of zero-emissions process controllers that do not emit methane to the atmosphere. Therefore, the final emission guideline maintains the proposed zero-emissions presumptive standard.

4. Compliance Dates

Comment: Several commenters state that a 60-day compliance deadline for new/modified sources is unrealistic due to supply chain concerns, personnel shortages, and inflation. Due to supply chain shortages and disruption, one commenter remarked that generators and other equipment and parts necessary for zero-emissions systems can take up to 3 months or longer for delivery, while another reports that they currently experience lead times for non-natural-gas-driven pneumatic controllers, generators, and air compressors ranging from 12 to 24 months. The commenters note that there is no indication that this lead time will improve in the near future and believe it can be expected to worsen as owners and operators across the country increase demand in response to the final rule. Commenters contend that this leaves even the most responsible owner or operator without the ability to comply within 60 days. Some commenters recommend a compliance deadline of 24 months from the publication date of the final rule and others propose at least a 1-year timeframe for NSPS OOOOb compliance to allow for procurement and installation of the systems and equipment necessary (including labor necessary for installation).

One commenter contends that supply chain considerations do not alter the reasonableness of the EPA's proposal. The commenter relays that EQT, the largest natural gas producer in the U.S., retrofitted all its sites to eliminate natural gas-driven controllers in less than 1.5 years and another oil and gas producer anticipates it will have replaced “nearly all” of its controllers with zero-emitting devices within 4 years. The commenter adds that a recent report by Datu Research further underscores that the supply chain for the production of zero-emitting technologies is not a barrier for industrywide adoption of zero-emissions controllers and that, on the contrary, the supply chain is strong enough to support implementation of the EPA's proposed standards. According to the commenter, Datu's report identifies 40 providers of zero-emitting controllers, and a survey of nine of these providers demonstrates that suppliers are well-equipped to meet anticipated demand within the EPA's proposed regulatory timeline. The commenter remarks that some key findings of the Datu report include the following:

• Technology providers have strategies for meeting current supply chain challenges. Though procurement delays have been a reality for some suppliers, they have employed strategies like paying higher prices, storing extra quantities of supplies, bringing in more procurement personnel, going to different distributors, spot-buying on the open market, and finding contract manufacturing sites. Larger companies reported facing fewer hurdles.

• Regulatory certainty steadies demand. Even considering supply chain concerns, providers have confidence in their ability to expand production capacity so long as regulatory certainty helps keep demand steady over multiple years.

Response: Based on these comments, it appears that some equipment necessary for the installation of zero-emitting process controllers may not be available quickly enough, and in large enough quantities, to enable new sources to comply with the final standard upon startup, or within 60 days after the publication of the final NSPS. Supplemental information submitted by one commenter provided information regarding current equipment lead time and market conditions. According to that information, some of the operators surveyed report that they are experiencing delays in the availability of process controllers, electrical transformers, generator skids, and compressor skids of up to 12 months. In addition, the zero-emissions technology supplier survey information also indicates that some equipment providers will need to ramp up production, and some components may not be widely available within 60 days after the publication of the final rule.

The equipment types discussed in the information provided by these commenters are relevant to the installation of zero-emitting controllers. Further, the equipment types that the EPA believes are necessary to comply with the final standards for process controllers in NSPS OOOOb are quite different from the type of equipment used to comply with the standards for these sources found in NSPS OOOOa. For example, compliance with NSPS OOOOa for most sources likely does not require electrical transformers, generator skids, or compressor skids. Due to these considerations, the EPA is not certain that new sources could obtain the equipment necessary to demonstrate compliance immediately upon the effective date of the final rule and is therefore finalizing a compliance deadline for process controllers that allows for up to 1 year from the effective date of the final rule. This means that new sources will have up to 1 year to come into full compliance with the final standard of zero emissions. Until that final date of compliance, owners and operators must demonstrate compliance with an interim standard which mirrors the requirements for sites in Alaska that do not have access to electrical power found at 40 CFR 60.5390b(b). In summary, the requirements for such sites allow for two compliance options. One option is to use low-bleed controllers and/or intermittent vent controllers, and to perform monitoring of intermittent vent controllers to ensure they do not vent during idle periods. The other option is to route process controller emissions to a control device achieving a 95 percent reduction in emissions. As the current NSPS OOOOa requires that low-bleed controllers be used, owners/operators of new and recently modified or reconstructed sites will be able to readily obtain the equipment necessary for these types of process controllers. Complying with the interim standard described above does not require using the equipment that commenters claimed they could not easily obtain ( i.e., the equipment needed to meet the zero-emissions standard). Therefore, the EPA expects no sites to have any problems complying with these interim requirements within 60 days after publication of the final rule. If an owner or operator opts to comply with the interim standard during the one year following publication of the final rule, then they must still comply with the final zero-emissions standard after the year has passed. Owners and operators can, and are encouraged to, comply with the final zero-emissions standard before the year has passed.

6. Modification and Reconstruction Criteria and Requirements

Under 40 CFR 60.14, any physical or operational change to an existing facility resulting in an emissions increase is a modification. In the December 2022 Supplemental Proposal, we stipulated that in addition to this definition of a modification, a modification would occur for purposes of this particular affected facility when a process controller is added to a site, as this addition would increase emissions from the affected facility, which is the collection of controllers at a site.

Comment: Commenters requested that the EPA clarify that, for purposes of the collection of process controllers at a site, a modification would occur only when a natural gas-driven process controller is added, rather than the addition of any type of process controller. The commenters pointed out that the addition of a controller not driven by natural gas would not increase emissions from the affected source.

Response: While it was our intention in the December 2022 Supplemental Proposal to only include the addition of natural gas-driven controllers in the conditions that would constitute a modification, as only those controllers could potentially increase emissions, we agree that the proposed regulatory text did not specify this. We therefore have changed what we proposed for regulatory language to clarify that the addition of one or more natural gas-driven controllers to a site constitutes a modification.

Comment: Commenters also requested that the EPA clarify which controllers would be considered in the determination of whether a reconstruction has taken place. In the December 2022 Supplemental Proposal, we included provisions that would allow owners and operators to choose to determine whether a reconstruction has occurred as it is defined in 40 CFR 60.15(b), based on the fixed capital cost of new process controllers, or they could determine whether a reconstruction had occurred based on the percentage of the total number of process controllers replaced.

Response: Like the provisions for modifications, we are clarifying in the final rule that reconstruction would be considered to occur whenever greater than 50 percent of the number of existing onsite natural gas-driven process controllers are replaced, rather than the replacement of any type of process controller, as only natural gas-driven process controllers are considered to be affected facilities for the NSPS.

Comment: In addition to these clarifications regarding the criteria for determining whether a modification or reconstruction has taken place, one commenter stated that it is unclear how the notification requirements of 40 CFR 60.15 apply for reconstruction. The commenter noted that the proposed language in 40 CFR 60.5365b(d)(2)(ii) suggests that reconstructed natural gas-driven process controllers would be subject to some of the requirements included in 40 CFR 60.15, which include 60-day notification and Administrator approval. According to the commenter, this conflicts with information presented in table 5 of the proposed regulatory text, which stated that 40 CFR 60.15(d) does not apply to process controllers. The commenter believes it was the EPA's intent to not apply the additional notification and approval, given the number of facilities that will trigger reconstruction over time.

Response: We agree that we did not intend for facilities to be required to notify the Administrator of upcoming process controller replacements that would constitute a reconstruction or for the Administrator to be required to review the notification and determine whether the replacements constitute a reconstruction. We have changed what we proposed for regulatory text to not refer to the requirements of 40 CFR 60.15(d) and have kept the information presented in table 5 of the proposed regulatory text, which states that 40 CFR 60.15(d) does not apply to process controllers.

7. Change in Pneumatic Controller Terminology

To assist with avoiding possible confusion about which types of “controllers” are included in the definition of this affected facility, and which types of controllers must be considered for purposes of the reconstruction and modification provisions, we have changed the terminology from “pneumatic controllers” (used in both the November 2021 Proposal and the December 2022 Supplemental Proposal) to “process controllers” in the final rule. When reviewing comments, the EPA noticed that not all commenters used the same terminology, so the Agency thought it best to clarify now. The EPA has made this change both in the final rule preamble and the final regulatory text. The term “process controller” is broader in scope because it includes pneumatic controllers as well as other types of controllers that are not pneumatic. Only a subset of process controllers used by oil and gas facilities are pneumatic controllers that use pressurized air (compressed air or instrument air) or gas to perform their functions. Other process controllers might use electricity to perform their functions. From a technical perspective, electronic process controllers are not true “pneumatic” devices, but these electronic process controllers can be used to perform the same function as a pneumatic controller, and they achieve the zero-emissions standard. The EPA changed the terminology because we did not want to inadvertently convey that misimpression that process controllers had to be pneumatic. To be clear, the final rule applies to the collection of natural gas-driven process controllers at a well site. Process controllers that are not driven by natural gas are not included in the affected facility. Further, only process controllers driven by natural gas will be counted when determining whether a modification or reconstruction has occurred.

E. Pumps

In the December 2022 Supplemental Proposal, the EPA proposed for both the NSPS OOOOb and EG OOOOc to define the pumps affected facility, and designated facility, as the collection of all natural gas-driven pumps at a site. For a limited subset of the affected pump facilities, the EPA proposed a tiered structure of standards based on conditions at the affected facility. Among other comments, the EPA received comments regarding: (1) the BSER analysis and conclusions, (2) the compliance dates, (3) the requirements associated with the tiered approach for some pumps, (4) the recordkeeping and reporting requirements for pumps not included in the definition of the affected facility, and (5) the criteria that would determine whether an affected pump facility was modified or reconstructed. These comments and the EPA's responses to these comments apply to the standards and presumptive standards in NSPS OOOOb and EG OOOOc, respectively. A summary of the comments received and the EPA's response to these comments, including any updates made to the final rule, as applicable, are provided below. The EPA's full response to comments on the November 2021 Proposal and December 2022 Supplemental Proposal, including any comments not discussed in this preamble, can be found in the EPA's RTC document for the final rule.

In addition to the updates made to the final rule to address these comments, one other change in terminology was made to address the types of equipment that may be used to perform the functions of pumps. That change is discussed further here.

1. BSER Analysis and Conclusions

The EPA received several comments regarding the proposed standards for pumps, including requests that the BSER analyses for pumps be revised to more closely match the analyses conducted for process controllers, requests for technology-neutral standards, and comments regarding the infeasibility certifications required.

Comment: One commenter states that the EPA relied on costs from the 2016 and 2021 Carbon Limits reports for process controllers, but that the EPA used different costs and assumptions as they pertained to converting to electric (assumed to be grid power) and solar pumps, which are not well documented and appear to be based on old information dating back to 2012.

Another commenter remarked that the EPA proposed a set of requirements for natural gas-driven process controllers completely distinct from that for natural gas-driven pumps, with sometimes conflicting statements made to justify the EPA's decisions. The commenter requested that the requirements for both process controllers and pumps be streamlined for consistency, with technology-neutral standards that do not require additional certifications and that allow for emissions to be routed to a control device. Another commenter urged the EPA to mirror the proposed process controller standard for pumps by including pumps routed to a process as a compliance option and eliminating the tiered feasibility exemption at sites without electricity.

Response: The EPA acknowledges that the analysis for pumps in the December 2022 Supplemental Proposal relied on costs from previous analyses that were updated to reflect changes in prices due to inflation. However, those cost figures used in the December 2022 Supplemental Proposal did not reflect more recent changes that have occurred in control technology or the impact of those changes on costs, such as a reduction in costs for solar panels and batteries. Therefore, the EPA updated its analysis for pumps to use the more recent information for non-natural gas-driven pump options. This included information from the Carbon Limits reports, which addressed pump options as well as process controllers.

A summary of the results of the updated analysis showing the cost effectiveness of the pumps affected facility emissions control options is shown in table 20. Further information regarding the analysis conducted for pumps may be found in the NSPS OOOOb and EG OOOOc TSD for this final rulemaking, which is available in the docket for this action. The cost effectiveness values shown in table 20 are based on the estimated total annual costs and the emissions reductions associated with each control option. The emissions reductions for a combustion control device are assumed to be 95 percent and are assumed to be 100 percent for all other control options evaluated. For new sources that will be covered by NSPS OOOOb, cost effectiveness was calculated on a single-pollutant basis, where the total annual cost was applied entirely to the reduction of each pollutant, and was also calculated on a multipollutant basis, where half the cost of control is assigned to the methane reduction and half to the VOC reduction. Table 20 shows the cost effectiveness values for GHG (methane) and VOC, which is applicable for the determination of BSER for new sources. Table 21 provides the cost effectiveness for GHG (methane) for existing sources. Further information regarding the cost effectiveness values for pumps may be found in the NSPS OOOOb and EG OOOOc TSD for this rulemaking, which is available in the docket for this action.

As seen in tables 20 and 21, for sites without electricity with three diaphragm pumps, the cost effectiveness values for all options fall within the ranges typically considered reasonable by the EPA. Specifically, for new sources at production sites, the single-pollutant cost effectiveness of solar-powered electric controllers is $395 per ton of methane and $1,421 per ton of VOC. For compressed air systems driven by a generator, the single-pollutant cost effectiveness value for methane is $1,857 per ton, which is considered reasonable, as are the multipollutant cost effectiveness values ($929 per ton of methane and $3,341 per ton of VOC). For the transmission and storage segment, the single-pollutant methane cost effectiveness for solar-powered electric controllers is $302 per ton and $1,422 per ton for compressed air systems driven by a generator. These are both within the range considered reasonable for methane.

For existing sources without access to grid power, the methane cost effectiveness value for production sites with three diaphragm pumps is $395 per ton for solar-powered electric pumps and $2,048 per ton for compressed air systems powered by a generator. At transmission and storage sites, for the otherwise same sources (existing sources without electricity, with three diaphragm pumps), methane cost effectiveness values are $302 per ton for solar-powered electric pumps and $1,567 per ton for compressed air systems powered by a generator. These values are all within the ranges considered reasonable for methane.

For sites without electricity with one or two diaphragm pumps, the cost effectiveness values for compressed air systems powered by a generator are not consistently within the range considered reasonable by the EPA. This leaves solar-powered electric pumps as the only option evaluated that has cost effectiveness values in the range considered reasonable by the EPA for both the production and the transmission and storage segments. However, the EPA has some concerns about the technical feasibility of solar-powered pumps in some situations. Specifically, the Carbon Limits report, which was a reference the EPA relied upon for this analysis, states that “[s]ites with a large number of pumps or with pumps with high energy or power demand may represent a challenge for 100 percent solar-powered electric systems. In addition, shortly after completion, some wells may require high volumes of methanol injection, and powering pumps to inject this high volume can strain these systems.”

While the EPA believes that solar-powered pumps are suitable for some applications, the EPA acknowledges concerns about their technical feasibility in some situations experienced at oil and gas sites. The EPA concluded that it is not appropriate to establish BSER based solely on solar-powered pumps. Therefore, the EPA created three subcategories: (1) Pumps at sites with access to electrical power, (2) pumps at sites without electrical service with three or more natural gas-driven diaphragm pumps, and (3) pumps at sites without electrical service with fewer than three natural gas-driven diaphragm pumps. The BSER determinations for these categories are discussed below. These determinations apply for both new and existing sources.

a. Pumps at Sites With Access to Electrical Power

The options evaluated for sites with electrical power are electric pumps and pneumatic pumps driven by compressed air systems. The EPA considers both of these options to be adequately demonstrated. For all scenarios at sites with electricity, the cost effectiveness values are within the range considered reasonable by the EPA (see tables 20 and 21). There could be secondary air impacts associated with the generation of the additional electricity, but those impacts are expected to be negligible. See the NSPS OOOOb and EG OOOOc TSD for this rulemaking for a discussion of these impacts. In conclusion, the EPA determined that a zero-emissions standard represents the BSER for pumps at sites with access to electrical power. This includes all diaphragm and piston pumps included in the affected facility at the site.

b. Pumps at Sites Without Electrical Service With Three or More Natural Gas-Driven Diaphragm Pumps

The options evaluated for sites without access to electrical power are solar-powered electric pumps and pumps driven by compressed air systems powered by a generator. As discussed above, the EPA considers pumps driven by compressed air systems powered by a generator to be adequately demonstrated. While the EPA recognizes the technical limitations of solar-powered pumps for some applications, the EPA finds that they are an option for many sites. For all scenarios where three or more diaphragm pumps are present at a site without electricity, the cost effectiveness values for both solar-powered pumps and compressed air systems are within the range considered reasonable by the EPA (see tables 20 and 21). There will be secondary air impacts associated with the use of generators, but based on a site-specific analysis, the EPA concludes that the benefits of the methane and VOC reductions outweigh the potential negative impacts. See section XI.D.2 of this document and the NSPS OOOOb and EG OOOOc TSD for this rulemaking for a discussion of these secondary air impacts from generators. While not shown here, for sites without access to electrical power that contain only piston pumps, the EPA did not identify any control options resulting in zero emissions that were considered cost effective. However, if a non-natural-gas zero-emissions system is installed to reduce diaphragm pump emissions, it would be cost effective to also use zero-emissions piston pumps. Therefore, the BSER determination for pumps at sites without access to electrical power and three or more diaphragm pumps is zero emissions of GHG (methane) and VOC. This is the BSER determination regardless of the number of piston pumps at the site. In conclusion, the EPA determined that BSER for pumps at sites with three or more diaphragm pumps without access to electrical power is zero emissions of methane and VOC from all diaphragm and piston pumps at the site.

c. Pumps at Sites Without Access to Electrical Power With Fewer Than Three Natural Gas-Driven Diaphragm Pumps

As discussed above, given the EPA's conclusion that solar-powered pumps are not technically feasible for some common applications and the fact that the analysis did not show cost effectiveness values of a compressed air system powered by a generator to be consistently within the range that the EPA considers reasonable at sites with fewer than three diaphragm pumps, the EPA concludes that a zero-emissions standard does not reflect the BSER for sites without access to electrical power that have fewer than three diaphragm pumps.

For this subcategory, the EPA evaluated other emissions control options, including routing the emissions to a process and routing the emissions to a combustion device. In most cases, a VRU will be required to enable the captured gas from the pump to be routed to a process. Therefore, costs were estimated for installing a closed vent system and VRU in order to route the gas to a process. It was assumed that this would achieve a 100 percent reduction in methane and VOC emissions. Costs were also estimated to install a closed vent system and a new combustion device to reduce the emissions, assuming a methane and VOC reduction of 95 percent. The EPA considers both routing emissions to a process and routing emissions to a combustion device to be adequately demonstrated emissions reduction techniques. As shown in tables 20 and 21, both options of routing emissions to a process via a new VRU or to a new combustion device have cost effectiveness values outside the ranges the EPA considers reasonable. Therefore, the EPA concludes that requiring the installation of a new VRU or control device for pumps at these sites is not the BSER.

The EPA also evaluated routing emissions through an existing VRU to a process (or routing directly to a process if that is possible) and routing emissions to an existing combustion device. Both of these options are adequately demonstrated since the emissions reduction technique is already being used for other equipment at the site. Further, the cost effectiveness of both options is in the range considered reasonable by the EPA. Therefore, the EPA concludes that, for sites without access to electricity and fewer than three diaphragm pumps, the BSER is routing to a process where an existing VRU is available or to a combustion device where an existing one is available.

d. Summary of Final Rule

Considering our revised analysis and BSER determinations, for affected and designated facilities at sites with access to electrical power and at sites without access to electrical power with three or more diaphragm pumps, the final rule and presumptive standard require these facilities to have zero GHG (methane) and VOC emissions from all diaphragm and piston pumps. Zero emissions may be achieved either by using pumps not powered by natural gas (and thus not an affected or designated facility) or by routing natural gas-driven pump emissions through a CVS to a process. As explained in the December 2022 Supplemental Proposal, the EPA understands that emissions routed through a CVS to a process would achieve a 100 percent emissions reduction from the pumps and therefore would meet a zero-emissions VOC and GHG standard. Like what was included in the supplemental proposal, the CVS demonstration requirements that there are no identifiable emissions from the CVS apply in the final rule. Unlike what was proposed, the final rule does not require a demonstration that using pumps not driven by natural gas is infeasible before compliance by routing emissions to a process is allowed.

For sites without access to electrical power with fewer than three diaphragm pumps, the final requirements are that natural gas-driven pump emissions must be routed through a CVS to a process if the site has a VRU, but if the site does not have a VRU, emissions can be routed to an onsite control device that achieves a 95 percent emissions reduction. If there is no control device onsite that achieves a 95 percent emissions reduction, emissions must be routed to a control device(s) onsite that achieves less than a 95 percent emissions reduction. If no VRU or control devices are onsite, emissions from natural gas-driven pumps are not required to be controlled. A summary comparison of the emissions standards included in the December 2022 Supplemental Proposal and the final rule is included in table 22.

It should be noted that there are similarities between the BSER analyses for natural gas-driven pumps and natural gas-driven process controllers. For both types of sources, the EPA evaluated a number of options that are not powered by natural gas and thus have zero methane and VOC emissions. As discussed above, for sites without access to electrical power with fewer than three diaphragm pumps, there are no cost-effective zero-emissions control options that the EPA found to be adequately demonstrated. For pumps at these sites, the only zero-emissions option with values the EPA considers to be cost-effective was solar-powered pumps. Given the power needs for some pumps to properly operate and the potential inadequacies of solar-powered systems to provide that amount of energy, the EPA determined that solar-powered systems do not represent BSER for pumps. Therefore, the EPA created a subcategory for sites without access to electrical power and fewer than three pumps and established different emissions control requirements for that subcategory. In contrast, for controllers, there was more than one adequately demonstrated zero-emissions option evaluated for every sized model plant throughout the sectors with cost effectiveness values considered reasonable. Therefore, even if there are power limitations for solar-powered process controllers, which require much less energy than pumps to properly operate, there are other cost-effective zero-emissions options available, and consideration of other emissions control options or subcategories of process controller affected facilities was not necessary.

Comment: In the December 2022 Supplemental Proposal, the EPA proposed a hierarchy of emissions control requirements for sites that did not have access to electrical power. Under this approach, the EPA proposed that an owner or operator would be required to first evaluate pump options that do not use natural gas and provide a certified demonstration that such options are infeasible before being allowed to use the next tier of emissions control options. For instance, at sites without access to electrical power, the proposal allowed for pump emissions to be routed to a process, but only after certified assessments were made demonstrating that it was technically infeasible to use solar-powered pumps and infeasible to use pumps powered by compressed air. One commenter stated that the EPA should remove the certifications associated with the hierarchy of pump compliance options. The commenter stated that the proposed certification requirements are unreasonably onerous because, in each case, the certifying individual must essentially prove a negative—that the otherwise applicable zero-emissions approaches are “technically infeasible.” The commenter stated that there is no definition of technical infeasibility in the proposed rule, but the words could be construed as setting an exceedingly high bar, such that a given non-emitting technique is “infeasible” based solely on a technical assessment of whether it can theoretically be physically applied in the given situation, even though it could be inordinately expensive. According to the commenter, this outcome would not be lawful because it would violate the statutory requirement that BSER and the corresponding standard of performance must be cost-effective. The commenter added that a “technical infeasibility” standard allows for second-guessing by regulators or citizen enforcers, which invites a “battle of the experts” in potential enforcement actions. According to the commenter, this diminishes the possibility that the opt-outs can be implemented with reasonable certainty.

The commenter also reported that the express threat of possible personal liability on the part of certifiers will limit the number of individuals willing to make the needed certifications, particularly considering the uncertainties about what will be needed as a practical matter to demonstrate “technical infeasibility.” The commenter stated that the clear opportunity and possibility of second-guessing will be further material disincentives.

Response: In consideration of these comments, the EPA reviewed the proposed “certification of infeasibility” requirements. The EPA restructured the final standards for pumps based on comments received on the December 2022 Supplemental Proposal. The final rule no longer includes the complex hierarchy of technical feasibility demonstrations that was included in the December 2022 Supplemental Proposal. Instead, the final rule includes a subcategory based on clear criteria such that sources can be certain as to which emissions standards apply without demonstrations of technical infeasibility.

Comment: One commenter mentioned that the EPA proposed to allow operators to route natural gas-driven pump emissions to a control device, but only if the operators can demonstrate that routing to a process is technically infeasible and that it is infeasible to use pumps not driven by natural gas. The commenter urged the Agency to recognize the substantial investments that operators have already made to route emissions from pumps to control devices by allowing any natural gas-driven pump to be routed to controls—not only in situations where non-natural-gas technology and routing to a process are each technically infeasible.

Response: As explained above, for the final rule we have removed the proposed requirement for demonstrations of technical infeasibility before the use of other equivalent control options may be used for pumps. In the final rule, we have further added the conditions under which pump emissions may be routed to a control device, which reflect our BSER determinations. For sites without access to electrical power and that have two or fewer diaphragm pumps, pump affected facility emissions may be routed to a control device if there is no VRU onsite.

2. Compliance Dates

Comment: Two commenters state that a 60-day compliance deadline for new/modified sources is unrealistic due to supply chain concerns, personnel shortages, and inflation. Due to supply chain shortages and disruption, one commenter reports that companies are experiencing backorders for some equipment, including non-natural-gas-driven pumps, generator skids, and air compressor skids, with current lead times ranging up to 12 months. The commenters note that there is no indication that this lead time will improve in the near future and believe it can be expected to worsen as owners and operators across the country increase demand in response to the final rule. One commenter recommended a compliance deadline of 12 to 26 months from the publication date of the final rule and one commenter proposed at least a 1-year timeframe for NSPS OOOOb compliance to allow for procurement and installation of the systems and equipment necessary (including labor necessary for installation).

One commenter requested that the EPA extend implementation timelines—particularly for sources that became NSPS OOOOb affected facilities prior to the date of final rule publication. The commenter remarked that until the effective date of NSPS OOOOb, some of these facilities would be unregulated under an existing NSPS or would begin operating as NSPS OOOOa affected facilities and may then need to complete retrofits to comply with newly applicable NSPS OOOOb standards. For example, the commenter states that NSPS OOOOa pneumatic pumps are not subject to a zero-emissions standard but would be subject to zero-emissions standards under NSPS OOOOb, requiring retrofit within 60 days after the final rule's publication in the Federal Register . According to the commenter, this is not enough time to acquire retrofit equipment that will be in high demand, and likely short supply, as operators across the country place orders for equipment to meet the zero-emissions standard. In addition, the commenter reports that operators must acquire engineering resources to engineer the installation of zero-emissions pneumatic systems. They report that these engineering resources, too, are likely to be in high demand and short supply. The commenter asserts that the timing of compliance obligations is particularly pronounced for pneumatic pumps, as according to the commenter, operators may no longer use pneumatic pumps that are driven by natural gas, subject to limited exceptions. The commenter notes that the November 2021 Proposal did not go so far as to eliminate the use of natural gas-driven pneumatic pumps entirely. The commenter states that operators may need to completely replace natural gas-driven pneumatic pumps that would have complied with the standards described in the November 2021 Proposal.

Response: Based on these comments, and for the same reasons explained in section XI.D.4 of this preamble for process controllers, the EPA is finalizing a NSPS compliance deadline for pumps required to meet a zero-emissions standard that allows for up to 1 year from the effective date of the final rule.

The equipment that owners and operators will need to comply with the final standard of zero emissions for pumps is, in some situations, the same equipment that owners and operators will need to comply with the final standard for process controllers. Based on comments, it appears that some equipment necessary for the installation of zero-emitting pumps may not be available quickly enough, and in large enough quantities, to enable new sources to comply with the final standard upon startup, or within 60 days after the publication of the final NSPS. As is the case for process controllers, the equipment types that the EPA believes are necessary to comply with the final zero-emissions standard for pumps in NSPS OOOOb are quite different from the type of equipment used to comply with the standards for these sources found in NSPS OOOOa. Due to these considerations, the EPA is not certain that new sources needing to meet the zero-emissions standard could obtain the equipment necessary to demonstrate compliance on the proposed timeline. This change to the final rule compliance timeline in NSPS OOOOb for pumps does not apply to sites without access to grid electricity that have fewer than three diaphragm pumps because those sites are not required to demonstrate zero emissions.

Until the final date of compliance with the zero-emissions standard, owners/operators must demonstrate compliance with an interim standard which mirrors the requirements for pumps at sites without access to grid electricity that have fewer than three diaphragm pumps found at 40 CFR 60.5393b(b). In summary, the standards for these sites require that GHG and VOC emissions from all natural gas-driven pumps in the affected facility be routed to a process if a VRU is onsite. If a VRU is not onsite, emissions must be reduced by 95 percent if a control device with at least this emissions reduction capability is already available onsite or may be reduced by less than 95 percent if a control device is onsite but is not capable of reducing GHG and VOC emissions by 95 percent or more. As these requirements are similar to the current NSPS OOOOa requirements for pumps at well sites, owners/operators of new and recently modified or reconstructed sites subject to NSPS OOOOb will be able to readily obtain the equipment necessary for this interim standard, to the extent that equipment is even necessary. The only difference compared to NSPS OOOOa is that NSPS OOOOb requires emissions to be routed to a process if a VRU is already on the site. The information available to the EPA and provided by commenters does not suggest any equipment backlogs for common piping that may be needed to route emissions to a process through a VRU. Complying with the interim standard described above does not require using the equipment that commenters claimed they could not easy obtain ( i.e., the equipment needed to meet the zero-emissions standard). Therefore, the EPA expects no sites to have any problems complying with these interim requirements within 60 days after publication of the final rule. If an owner or operator opts to comply with the interim standard during the one year following publication of the final rule, then they must still comply with the final zero-emissions standard after the year has passed. Owners and operators can, and are encouraged to, comply with the final zero-emissions standard before the year has passed.

3. Recordkeeping and Reporting Requirements for Pumps Not Included in the Affected Source

Comment: Commenters pointed out that 40 CFR 60.5410b(g)(1) requires owners and operators to submit an identification of all pumps that are not powered by natural gas in the initial annual report required by 40 CFR 60.5420b(b)(10)(i), and such pumps are not part of the pumps affected facility definition. The commenters recommended that owners or operators only be required to maintain records sufficient to determine compliance with the regulations. The commenters contend that having requirements for equipment that is not part of an affected source exceeds the EPA's authority granted under CAA section 111 and add that there is no environmental benefit to keeping or submitting information for equipment that cannot have emissions. The commenters recommended that the EPA remove any reporting or recordkeeping requirements for these pumps from the final regulations.

Response: After considering this comment, we have determined that it is appropriate in this instance to require identification of the equipment that is included in the affected facility, rather than the equipment that is not part of the affected facility. The pumps included in the affected facility are those that are subject to the emissions standards in the rule, whereas pumps not included in the affected facility are not subject to the emissions standards in the rule and also have no potential to emit methane or VOCs. Therefore, we have revised the recordkeeping requirements to require identification only of pumps that meet the finalized definition of an affected facility, which are those pumps that are driven by natural gas and that are in operation for 90 days or more in a calendar year.

4. Modification and Reconstruction Criteria and Requirements

Comment: Commenters requested that the EPA clarify that, for purposes of the collection of controllers or pumps at a site, a modification occurs only when a natural gas-driven pump is added. The commenters pointed out that the addition of a pump not driven by natural gas would not increase emissions from the affected source. Commenters also requested that the EPA clarify which pumps would be considered in the determination of whether a reconstruction has taken place.

Response: While it was our intention in the December 2022 Supplemental Proposal to only include the addition of natural gas-driven pumps in the conditions that would constitute a modification, as only those pumps could increase emissions, we agree that the proposed regulatory text did not specify this. We therefore have updated what we proposed for regulatory language to clarify that the addition of one or more natural gas-driven pumps to a site constitutes a modification. We also are clarifying in the final rule that reconstruction would be considered to occur whenever greater than 50 percent of the number of existing onsite natural gas-driven pumps are replaced.

Comment: In addition to these clarifications regarding the criteria for determining whether a modification or reconstruction has taken place, one commenter stated that it is unclear how the notification requirements of 40 CFR 60.15 apply for reconstruction. The commenter noted that the proposed language in 40 CFR 60.5365b(d)(2)(ii) suggests that reconstructed natural gas-driven pumps would be subject to some of the requirements included in 40 CFR 60.15, which include 60-day notification and Administrator approval. According to the commenter, this conflicts with information presented in table 5 of the regulatory text, which states that 40 CFR 60.15(d) does not apply to pumps. The commenter believes it was the EPA's intent to not apply the additional notification and approval, given the number of facilities that will trigger reconstruction over time.

Response: We agree that we did not intend for facilities to be required to notify the Administrator of upcoming pump replacements that would constitute a reconstruction or for the Administrator to be required to review the notification and determine whether the replacements constitute a reconstruction. We have updated what we proposed for regulatory text to not refer to the requirements of 40 CFR 60.15(d) and have kept the information presented in table 5 of the proposed regulatory text, which states that 40 CFR 60.15(d) does not apply to pumps.

5. Change in Pneumatic Pump Terminology

In addition to the revisions to the modification and reconstruction criteria and requirements for pumps, to assist with avoiding possible confusion about which types of pumps are included within the definition of the affected facility and which types of pumps must be considered for purposes of the reconstruction and modification provisions, we have changed the terminology of “pneumatic pumps” (used in both the November 2021 Proposal and the December 2022 Supplemental Proposal) to simply “pumps” in the final rule. The EPA has made this change both in the final rule preamble and the final regulatory text. The term “pumps” is broader in scope because it includes pneumatic pumps as well as other types of pumps that are not pneumatic. Only a subset of pumps used by oil and gas facilities are pneumatic pumps that use pressurized air or gas to perform their functions. Other pumps might use electricity to perform their functions. From a technical perspective, electronic pumps are not true “pneumatic” devices, but these electronic pumps can be used to achieve the zero-emissions standard. The EPA changed the terminology because we did not want to inadvertently convey that misimpression that pumps had to be pneumatic. To be clear, the final rule applies to the collection of natural gas-driven pumps. Pumps that are not driven by natural gas are not included in the affected facility. Further, only pumps driven by natural gas will be counted when determining whether a modification or reconstruction has occurred.

F. Wells and Associated Operations

In the December 2022 Supplemental Proposal, the EPA proposed to define a well affected facility, and well designated facility, to consist of a single well. The EPA also proposed standards for well affected facilities and designated facilities for oil wells with associated gas, gas wells that undergo liquids unloading, and wells that undergo completions. A summary of the comments received and the EPA's response to these comments, including any changes made to the final rule, as applicable, are provided below. The EPA's full response to comments on the November 2021 Proposal and December 2022 Supplemental Proposal, including any comments not discussed in this preamble, can be found in the EPA's RTC document for the final rule.

1. Well Affected Facility and Designated Facility Definitions

In the December 2022 Supplemental Proposal, rather than including three separate definitions for well affected facilities (as initially proposed in the November 2021 Proposal) for (1) oil wells with associated gas, (2) gas wells that undergo liquids unloading, and (3) wells that undergo completions, the EPA proposed a single definition for a well affected facility, which was defined as a single well, in the proposed NSPS OOOOb. A well is defined as a hole drilled for the purpose of producing oil or natural gas. The EPA proposed separate standards for well completions, associated gas from oil wells, and gas well liquids unloading operations, all or some of which could apply to a given well affected facility. A well affected facility would be required only to comply with the standards that are applicable to the well. For example, a gas well would not be subject to the standard for oil wells with associated gas. The proposed NSPS OOOOb specified that a modification to an existing well occurs when the definition of modification in 40 CFR 60.14 is met, including when an existing well undergoes hydraulic fracturing or refracturing.

For the EG OOOOc rule, the EPA proposed, similar to NSPS OOOOb, a definition of well designated facility as a single well. Modification provisions do not apply under EG OOOOc. The December 2022 Supplemental Proposal included proposed presumptive standards for associated gas from oil wells and gas well liquids unloading. However, since the fracturing or refracturing of an existing well would constitute a modification under NSPS OOOOb, which would make the well a well affected facility under NSPS OOOOb, there would never be an existing well subject to well completion requirements and no requirements are specified for well completions under EG OOOOc. More discussion of the well affected facility/designated facility specific to each of the three associated well operations is provided in sections X.F.2, 3, and 4 of this document.

The EPA did not receive comments on the proposed definition of a well affected facility or designated facility that warranted changes to what was proposed in the December 2022 Supplemental Proposal. Therefore, the definitions have been finalized as proposed.

2. Associated Gas From Oil Wells

In section X.F.2 of this document, the final NSPS OOOOb and EG OOOOc requirements for oil wells with associated gas are summarized. The EPA received many comments on the December 2022 Supplemental Proposal on the following topics: the definition of associated gas, the BSER analysis for new wells, BSER for existing wells, temporary venting and flaring, and the infeasibility determination and certification. For each of these topics, a summary of the proposed rule, the comments, the EPA responses, and changes made in the final rule (if applicable), are discussed here. These comments and the EPA's responses to these comments generally apply to the standards and presumptive standards in both the NSPS OOOOb and EG OOOOc respectively. The instances where the comment and/or response only applies to NSPS OOOOb or EG OOOOc are noted. The EPA's full response to comments on the November 2021 Proposal and December 2022 Supplemental Proposal, including any comments not discussed in this preamble, can be found in the EPA's RTC document for the final rule.

a. Definition of Associated Gas

Neither the November 2021 Proposal nor the December 2022 Supplemental Proposal included a definition of “associated gas.”

Comment: Several commenters suggested that a definition of “associated gas” be added. Commenters expressed that it is important for the EPA and the regulated community to have a common understanding of the definition of associated gas. One commenter added that, without a definition, the term “associated gas” could take on various meanings including the most literal interpretation of any gas associated with oil well production, which might include emissions from other NSPS OOOOb or EG OOOOc affected/designated facility types that the EPA regulates in other sections of its proposal— e.g., a collection of fugitive emissions components or storage vessels. Commenters provided several suggestions for this definition, including:

• Associated gas means the gas that can be separated from the produced liquids in the first stage of separation at a pressure sufficient for it to flow into the gathering system.
• Associated gas means the natural gas which originates at wells operated primarily for oil production and occurs either in a discrete gaseous phase at the wellhead or is released from the liquid hydrocarbon during the initial stage of separation after the wellhead.
• Associated gas means the natural gas which originates at oil wells operated primarily for oil production and occurs either in a discrete gaseous phase at the wellhead or is released from the liquid hydrocarbon during the initial stage of separation after the wellhead.

• Associated gas means the natural gas evolved from hydrocarbon liquids during the initial stage of separation following production from the wellhead. Associated gas does not include natural gas associated with well completion or downhole well maintenance activities.

Response: The EPA agrees with the commenters that a definition of associated gas would be beneficial to provide clarity to regulatory and enforcement agencies and to the regulated community. First, our intention is to regulate the gas that is released from the liquid at the first stage of separation, so we included that characteristic in the definition in the final NSPS OOOOb and EG OOOOc.

One commenter suggested that the EPA define associated gas by using the phrase “in a discrete gaseous phase at the wellhead,” arguing that this description is necessary to avoid a broad interpretation of associated gas that encompasses any gas associated with oil well production. The EPA believes that the commenter's suggested language is not necessary to clearly define associated gas and believes that it could add confusion.

We do not believe that the most literal interpretation offered by the commenter that any gas associated with oil well production might be considered associated gas, and we do not feel a need to include such a clarification in the definition. However, we recognize that there could be confusion between the emissions associated with well completions and associated gas. This is particularly the case in situations where a permanent separator has been placed onsite during the completion activities and used during the separation flowback stage. The definition of flowback in 40 CFR 60.5430b of the final rule specifies that the flowback period ends when either the well is shut in and permanently disconnected from the flowback equipment or at the startup of production. This provides a clear distinction between when the completion flowback requirements end and the associated gas production begins. Therefore, the final definition of associated gas includes the phrase, “Associated gas production begins at the startup of production after the flowback period ends.” The full definition of “associated gas” for this final rule is included below and can also be found at 40 CFR 60.5430b and 40 CFR 60.5430c.

Comment: One commenter requested that the EPA allow certain provisions for wildcat or delineation wells in its proposal with respect to the associated gas from oil well provisions. The commenter explains that such wells are exploratory in nature and are typically located in remote locations far from any form of permanent infrastructure, including gathering infrastructure. Wildcat or delineation wells will typically only produce for a short period of time after flowback ends in order to complete well testing, which is used to determine the production flow rate along with other parameters such as the gas composition before the well is shut in or capped in accordance with state protocols. According to the commenter, in many instances an operator will not know or understand the composition of the gas until after the well is drilled. The commenter suggests that this combination of characteristics makes it impracticable to install gas gathering infrastructure or plan for other forms of beneficial use at a wildcat or delineation well. Noting that the EPA has exempted such wells from NSPS OOOOa standards for well completions, the commenter recommends that the EPA allow special considerations for handling associated gas since these activities are exploratory in nature and are typically not located near existing infrastructure.

Response: The EPA acknowledges that the types of associated gas wells that are the focus of these rule requirements are wells that consistently produce, and potentially emit, natural gas. The temporary nature of wildcat and delineation wells is not conducive to warrant the construction of piping to connect to a natural gas gathering system or to utilize another solution where the gas could be used. Further, as noted by the commenter, the owners and operators of wildcat or delineation wells typically do not have knowledge of the nature and composition of the gas until after the well is drilled, which further hinders the ability to implement a beneficial-use solution. Therefore, the EPA has clarified in the definition of associated gas that gas from wildcat or delineation wells, which are defined in 40 CFR 60.5430b, is not associated gas for purposes of regulation under NSPS OOOOb and EG OOOOc. In response to these comments, the final rule includes the following definition in 40 CFR 60.5430b and 40 CFR 60.5430c:

b. BSER Analysis for New Wells

In the November 2021 Proposal, the EPA determined that the BSER for associated gas was routing the associated gas from oil wells to a sales line. In the preamble for the November 2021 Proposal (86 FR 63236–39), and in the associated TSD, the EPA evaluated several equivalent options that would all effectively eliminate direct emissions of VOC and methane from associated gas, including routing the associated gas to a sales line, utilizing the associated gas in a “beneficial” manner, and reinjecting the gas. Regarding the cost impacts of routing the gas to a sales line, the EPA assumed “that in situations where gas sales line infrastructure is available, there is minimal cost to owners and operators to route the associated gas to the sales line. While situations at well sites can differ, which would impact this cost, the EPA believes that in every situation the value of the natural gas captured and sold would outweigh these minimal costs of routing the gas to the sales line, thus resulting in overall savings.” 86 FR 63237. The EPA then concluded with, “Given the prevalence of this practice, the environmental benefit, and the economic benefits to owners and operators, the EPA concludes that BSER is routing associated gas from oil wells to a sales line.” 86 FR 63237. However, in 2021, the EPA also recognized that there are situations where there would not be access to a sales line and therefore also evaluated the costs and impacts of routing associated gas to a flare.

In the December 2022 Supplemental Proposal, the EPA again determined that BSER was routing the associated gas to a sales line and again proposed this requirement. The supplemental proposal also included that “[i]f access to a sales line is not available, the gas can be used as an onsite fuel source or used for another useful purpose that a purchased fuel or raw material would serve. If demonstrated that a sales line and beneficial uses are not technically feasible, the gas can be routed to a flare or other control device that achieves at least 95 percent reduction in methane and VOC emissions.” 87 FR 74710.

While no comments were received on the EPA's earlier assertion in the November 2021 Proposal that there would be minimal cost to route the gas to an available sales line, comments were received on the flaring analysis. As a result of these comments, the EPA updated the flaring analysis in the December 2022 Supplemental Proposal. This updated flaring analysis assumed an initial capital cost of $100,579 to install a new flare, which was the recommended cost provided by a commenter. Assuming a 7 percent interest rate and 10-year capital recovery period, along with an annual maintenance and operational cost of $25,000, the estimated annual cost was $36,044. Details of this cost estimate are included in the TSD for the December 2022 Supplemental Proposal.

The EPA also updated the analysis of the associated gas emissions in the December 2022 Supplemental Proposal because the analysis performed for the November 2021 Proposal included emissions from associated gas wells that the EPA concluded were not representative of “routine” venting situations. The resulting analysis was a representative well with uncontrolled potential associated gas emissions of 343.6 tpy of methane and 96 tpy of VOC. The details of this analysis may also be found in the TSD for the December 2022 Supplemental Proposal.

Comments were received on the December 2022 Supplemental Proposal related to the representative baseline emissions analysis and the assumption that the costs of routing to a sales line or other beneficial use were minimal.

i. Baseline Emissions for Representative Well

Comment: One commenter stated that the EPA seemed to bias the data selected for baseline emissions to fit their expectation rather than using actual reported data. The commenter cited section 6.3.1 of the supplemental proposal TSD.

Response: In the TSD for the December 2022 Supplemental Proposal, the EPA identified 95 facilities/basins that reported associated gas venting emissions (through GHGRP subpart W data) for 2019. For each facility/basin, the number of wells venting is reported, along with the total methane vented from all wells. For each facility/basin, we calculated the average emissions per well. These average well emissions ranged from 0.015 tpy to over 2,400 tpy. Almost 20 percent of the facilities/basins had average well methane emissions lower than 0.2 tpy.

Explanations of the specific causes of emissions are not provided in the GHGRP subpart W outputs, but it would be expected that routine venting of associated gas would result in emissions greater than this level as the DOE indicates that the average associated gas production for an oil well is around 7.5 boe per day, which would be around 450 tons of methane emissions per year. In order to avoid selecting a well associated gas venting level that was unreasonably low, a weighted average well emissions level was calculated, using the total emissions from the facility/basin as the weighting factor. The result is an estimated average annual methane emissions level of 344 tpy. Applying the representative composition yields a representative VOC emissions level of 96 tpy.

The intention of the analysis that the commenter discusses was to develop an emissions level estimate that represented the routine venting of associated gas—that is, situations where the associated gas was vented and not usually routed to a sales line or used for another purpose. As alluded to by the commenter, we assumed that the low emitting situations likely represent instances where venting was only temporary, and thus we discounted their contribution to the representative emissions level. As discussed in detail in section XI.F.2.f of this document, we recognized that the proposed rule did not adequately distinguish between “routine” and “temporary” situations. The final rule includes limited conditional allowances for venting in temporary situations where the associated gas is routed to a sales line normally (or used for another beneficial purpose) but due to circumstances or disruptions operators are not able to maintain normal operations without temporarily venting.

In conclusion, the EPA continues to believe that the associated gas emissions estimate levels used for the December 2022 Supplemental Proposal's representative well appropriately characterizes a well that routinely vents the gas. Therefore, no changes were made to the representative well emissions level.

ii. BSER Cost Analysis

As noted earlier in this document, both in the November 2021 Proposal and in the December 2022 Supplemental Proposal, we assumed that there would be minimal cost to route the gas to an available sales line, which was determined to represent BSER.

Comment: In comments on the December 2022 Supplemental Proposal, one commenter stated that the associated gas model plant analysis did not include assumptions reflective of actual proposed requirements. They pointed out that none of the beneficial reuse emerging technologies were included in the model plant analysis, and that it was unclear how the EPA justified the inclusion of these technologies related to costs, feasibility, or environmental benefit/disbenefit.

Another commenter also recognized that the EPA declined to quantitatively analyze the cost of routing to a sales line and the other beneficial use options, but the commenter provided a study that included estimates of the costs of various gas recovery options. Specifically, this study estimated the costs of routing to a sales line (pipeline gathering), onsite use (for fueling equipment or for local electricity generation), gas-to-wire, onsite compressed natural gas (CNG), onsite liquefied natural gas (LNG), and gas reinjection. Based on the cost data from this study, the commenter concluded that the cost effectiveness values for all abatement methods are well within the range that the EPA finds reasonable.

Response: While the first commenter indicated that the EPA did not perform an analysis of the BSER options, the commenter did not provide any information to support their comments. Contrary to this comment, the EPA did perform a BSER analysis. The EPA found the study provided by the second commenter to be informative regarding the extent of flaring in the U.S. and fundamental considerations in non-flaring abatement options. However, we closely examined this information and determined that the basis for these cost estimates lacked some details that the EPA thought necessary in order to use them as the basis for a BSER analysis. See EPA–HQ–OAR–2021–0317–2433 attachment T to review the data submitted.

In addition to following up with the single commenter that provided cost information for non-flaring options, the EPA performed a search for cost information from other sources. One source identified with detailed cost information that the EPA found to be informative was a study performed by ICF International for the Interstate Natural Gas Association of America (INGAA) Foundation. In addition to a plethora of information regarding midstream infrastructure, this study included detailed costs for the installation of gathering and boosting systems and associated lines. Specifically, it provided detailed cost information for, among other things, pipeline costs and compression/pumping costs. The gathering pipeline costs were provided starting in 2010 and projected to 2035 for pipe sizes ranging from 2 inches to 30 inches. In conversations with the authors of this report, the commenter indicated that the most representative pipe sizes for connecting a well to an existing gathering system were either 4 or 6 inches.

This information was used to estimate the costs for connecting the associated gas from a well site to a nearby gathering system/sales line for the representative well discussed earlier in this document. Specifically, costs were estimated for both 4- and 6-inch pipe sizes and for a variety of distances, in miles, to the gathering system. Other assumptions in this analysis were that the compressor horsepower needed was 25 horsepower and the capital recovery was based on 7 percent interest rate and 10 years. Annual operation and maintenance costs were estimated to be 25 percent of the total capital costs. Table 23 provides the results of this analysis.

As provided in table 23, the single-pollutant cost effectiveness for methane ranges from $158 to $3,219 per ton of methane emissions eliminated. If the value of the gas that will be sold ( i.e., the savings) is considered, the range is from a net savings to $3,037 per ton. The per-ton VOC cost effectiveness ranges from $569 to $11,580 without savings and ranges from a net savings to $10,927 considering the savings. The multipollutant cost effectiveness values range from $79 per ton of methane and $286 per ton of VOC to $1,609 per ton of methane and $5,790 per ton of VOC. If savings are considered, these multipollutant cost effectiveness values range from a net savings to $1,519 per ton of methane and $5,464 per ton of VOC. More details on this analysis are provided in the 2023 NSPS OOOOb and EG OOOOc Final Rule TSD.

The EPA determines that the estimated costs, for both pipe sizes for distances out to 50 miles are reasonable, when considering multipollutant reductions of methane and VOC. The EPA factors in that owners and operators of newly drilled wells have the flexibility to plan and coordinate the construction of gas gathering systems even over extended distances. Our analysis shows that constructing up to 50 miles of pipeline is a cost-effective means of managing associated gas at representative volumes of gas. In cases where the cost of construction of gathering line or gas volume differs significantly from these representative parameters, the other options for managing associated gas are available under the standards. The information presented in table 23 supports the assumption that the EPA made in the November 2021 Proposal and the December 2022 Supplemental Proposal that routing to a sales line is cost-effective.

c. BSER Conclusion for New Sources

In the December 2022 Supplemental Proposal, we concluded that BSER was routing the associated gas to a sales line. In addition, we recognized that there were other options that achieved the same level of emissions reduction as routing to a sales line. Therefore, we proposed four compliance options to reduce emissions of methane and VOC from associated gas from new oil wells. These options were: (1) recover the associated gas from the separator and route the recovered gas into a gas gathering flow line or collection system to a sales line, (2) recover the associated gas from the separator and use the recovered gas as an onsite fuel source, (3) recover the associated gas from the separator and use the recovered gas for another useful purpose that a purchased fuel or raw material would serve, or (4) recover the associated gas from the separator and reinject the recovered gas into the well or inject the recovered gas into another well for enhanced oil recovery.

Routing associated gas to a sales line is an adequately demonstrated method of emissions reduction. This is supported by the statements of one industry commenter, which indicated that recovering associated gas from the separator and routing the recovered gas into a gas gathering flow line or collection system to a sales line “explains standard business operations for thousands of wells producing a vital energy resource throughout the country.” They add that “[s]elling natural gas is part of our business.” The environmental benefit of routing associated gas to a sales line is significant, as there are no GHG (methane) or VOC emissions. As outlined in the TSD for this final rule, there are also minimal nonair quality health and environmental impacts related to routing gas into a sales line. Further, as discussed in section XI.F.2.b of this document, in response to comments, the EPA obtained information related to the costs of connecting to a sales line and performed an analysis, the results of which showed that the cost of routing to sales is reasonable given the emissions reductions. Given these considerations, the EPA again concludes that BSER is routing associated gas from oil wells to a sales line. In addition, the EPA continues to accept that the other three options proposed achieve equivalent emissions reductions to routing to a sales line and that they should be allowed as regulatory alternatives to the BSER.

The December 2022 Supplemental Proposal for new sources allowed the associated gas to be routed to a flare or control device that reduces methane and VOC emissions by at least 95.0 percent if a determination was made that it was not technically feasible to route the associated gas to a sales line, use it as onsite fuel or for another beneficial purpose, or inject/reinject it due to technical or safety reasons, and the determination was certified by a professional engineer or another qualified individual with expertise in the uses of associated gas. Ongoing, continuous flaring in the absence of a method for capturing and selling, putting to beneficial use, or storing associated gas is referred to as “routine” flaring. As described previously in this preamble and in response to comments described below, the EPA has changed these provisions for the final NSPS OOOOb rule to specify that routine flaring is disallowed at new wells that commence construction 24 months after the effective date of this final rule. As discussed in detail below, new sources can take this requirement into account when planning. Moreover, the final rule provides for an orderly “phase in” of this requirement through compliance deadlines that vary based on the date of construction, and it also recognizes reasonable exemptions for temporary or emergency uses of flaring. These requirements for new wells reflect comments and information the EPA received in response to the December 2022 Supplemental Proposal.

Comment: Numerous commenters supported the EPA's proposal to allow for multiple compliance options as alternatives to routing gas to a sales line, and several pointed out that the proposed list was consistent with the options allowed in New Mexico and Colorado. For instance, one commenter stated, “As in the EPA's supplemental proposal, Colorado and New Mexico require operators to capture associated gas from oil wells and either route the gas to a sales line or put it to an alternative use. The alternative uses allowed in New Mexico largely overlap with those included in the EPA's supplemental proposal and include, among other things, power generation on lease, liquids removal on lease, reinjection for underground storage, and other alternative uses approved by the division. For wells that are not connected to a pipeline, Colorado similarly allows operators flexibility to use other options to capture gas including to generate electricity or to process the gas to recover natural gas liquids, without venting or flaring.”

The commenter also recommended that the EPA remove any specific reference to “enhanced oil recovery.” The commenter explained that other preferable options exist for injected or reinjected gas, such as permanent storage in porous geological formations, and there is no reason to disallow or subordinate these alternatives.

Response: The EPA agrees with this comment and therefore has eliminated specific reference to enhanced oil recovery in the final rule for both NSPS OOOOb and EG OOOOc. Specifically, the fourth compliance option (alternative standard) under the final rule allows the recovery of associated gas from the separator and reinjection into the well or injection into another well. Removal of reference to enhanced oil recovery means that sources can choose to reinject regardless of whether doing so results in additional oil being produced or recovered from the well. This compliance option still results in equivalent emissions reductions to the BSER.

Comment: Many commenters objected to the allowance of routine flaring for new sources. One commenter urged the EPA to eliminate pollution from routine flaring except in emergency situations and to define the term “emergency” clearly and narrowly. The commenter recommended that exemptions only be applicable to short-term and temporary flaring. Another suggested that routine flaring from new wells can never be justified due to the technical infeasibility of some alternative. The commenter stated that routine flaring is readily preventable at new wells with proper planning and coordination. Another commenter urged the EPA to adopt NSPS and EG that effectively prohibit routine flaring of associated gas from new and existing oil wells, with the only exceptions related to safety and emergencies, by requiring owners or operators to capture all or most of the gas. Another commenter strongly supported the EPA's proposed requirement that owners and operators of oil wells with associated gas must capture that gas and route it to a sales line. However, they stated the belief that the EPA can and should take further steps to eliminate routine flaring. They asserted that the EPA should replace the broad technical infeasibility exception that would allow operators to continue routinely flaring with narrowly defined exemptions applicable only to short-term and temporary flaring. Another commenter called for a nationwide ban on routine flaring, characterizing the practice as wasteful and unnecessary. The commenter points out that leading state examples and the commitments made by multiple operators demonstrate that eliminating routine flaring is feasible and cost-effective.

The commenter noted that numerous operators have committed to eliminate routine flaring as part of the World Bank's “Zero Routine Flaring by 2030” initiative. To date, 54 oil companies and 34 governments have endorsed the “Zero Routine Flaring by 2030” initiative. Based on satellite estimates and publicly reported flaring data, together the endorsers represent approximately 60 percent of global flaring. The commenter added that ExxonMobil “recently announced a commitment to end routine flaring while also expressing support for regulations banning this wasteful practice.” They urged the EPA to revise its proposal to prohibit routine flaring by requiring that operators use one of the four gas recovery abatement methods included in the EPA's proposal. They suggested that the EPA allow for flaring only during explicit, narrowly tailored, and time-limited exemptions. They believed that doing so would more clearly and unequivocally prohibit pollution stemming from routine flaring, as well as enhance the enforceability of the rule.

One industry commenter reported that it is actively working to reduce flaring of associated gas across each of its operating areas and has committed to eliminate routine flaring by 2030. Since the commenter's standard practice is to only bring wells online where adequate sales line capacity exists, the commenter supports the restriction of the routine flaring of associated gas from oil wells that are considered “new” sources.

Commenters also pointed out that Colorado and New Mexico do not allow the long-term routine flaring of associated gas. One recommended that the EPA should follow the lead of these states and prohibit routine flaring of associated gas from new and existing oil wells except in very limited cases such as emergencies and for safety reasons.

One commenter stated that a standard based on approaches like those adopted in Colorado and New Mexico, which clearly limit and delineate circumstances where temporary flaring would be permitted, represents the “best system” for several reasons. For one, it would require gas recovery but contain reasonable exemptions for temporary flaring during certain activities that may require flexibility to vent or flare. Thus, this system would “reduc[e] emissions as much as practicable” and reflect the “maximum practicable degree of control.” The standard would permit technological flexibility by allowing the use of a multitude of abatement methods, including routing to a sales line, injection, or reinjection, use as onsite fuel, or use for another alternative purpose. The commenter pointed out that the costs of a capture standard are reasonable, cost-effective, and in some instances even profitable for operators.

Response: The EPA finds these arguments for not allowing routine flaring under any circumstance for new sources to be compelling. The EPA reviewed the comments from across the industry on our proposal to direct the gas to a sales line or adopt another gas management technique that did not require flaring. The conclusion that the EPA reached for new sources was that operators did not demonstrate or even explain that routing to a sales line or the alternatives were infeasible, only that specific circumstances could make certain alternatives more attractive than others. The most cited factors for deciding between the proposed alternatives were the logistics of each option and the costs of adopting any method as a function of the amount of available gas and whether the well was new, existing, or a marginal well nearing the end of production. Since the objective of our proposal was to cost-effectively minimize the emissions that result from associated gas, and flaring emits more than the zero-emissions options, we looked at the group of wells where the factors allowing a non-flaring option were most in favor of operators. New wells fit the criteria where factors worked most in favor of not flaring. New wells benefit from new investment and the benefit of planning to accommodate each option best suited to the site. Production is highest at startup, meaning that from the start of production a new well would have anywhere from 10 to 30 years of production to draw upon to manage and amortize the investment required to manage associated gas. Our analysis of the costs of connecting to a sales line indicated that for representative amounts of gas at reasonable distances, the outlook for amortization of the capital investment was reasonable. See table 22 above. Where distances or logistics might make connection to sales lines less attractive, commenters provided cost and qualitative support that the other alternatives would likely be used rather than connecting to sales, provided they had the benefit of space and time to plan for managing the associated gas when construction was beginning. As mentioned above, companies themselves have made voluntary commitments to eliminate flaring in the near future, by 2030. While those commitments are on a longer time horizon than this final rule, our decision to limit the prohibition on routine flaring to only new wells means the timelines between implementation of the NSPS and the voluntary commitments are in the range of about 4 years apart (considering the phase-in period for the final associated gas standards in the NSPS). We heeded industry comments that a significant time horizon would be required to make such a transition, and we chose 24 months from the effective date of the final rule as the most flexible option that would provide meaningful and timely reductions without disrupting the near-term investments taking place now. We concluded that, for new sources, opportunities exist for advance planning to route the associated gas to a sales line, use it as onsite fuel or for another beneficial purpose, or inject/reinject it. Therefore, in the final rule, the EPA has eliminated the allowance for new sources that associated gas can be routinely routed to a flare or other control device. As explained further below, the EPA is finalizing a phase-in approach for this standard for the NSPS OOOOb.

As discussed in section XI.F.2.f of this document, the EPA recognizes that a source routing the associated gas to a sales line, using it as onsite fuel or for another beneficial purpose, or injecting/reinjecting it will likely encounter temporary situations where it is infeasible or unsafe to route the associated gas to a sales line, use it as onsite fuel or for another beneficial purpose, or inject/reinject it. Therefore, the final rule allows temporarily routing to a flare or other control device in specified situations.

In addition, the EPA acknowledges that owners or operators may have already planned and initiated efforts to drill new wells based on the allowance of routing to a flare or control device with an infeasibility determination that was included in the December 2022 Supplemental Proposal. The EPA also accepts that existing wells that are modified or reconstructed may be limited in the options to route to a sales line or comply with one of the other options. Therefore, the final rule includes special allowances for these situations. This is discussed in section XI.F.2.d of this document.

d. Considerations for New Sources for Which Construction Commenced Prior to the Final Rule and for Reconstructed and Modified Sources

In the December 2022 Supplemental Proposal, the EPA proposed to allow new sources to routinely route associated gas to a flare or control device with a demonstration and certification that routing the associated gas to a sales line, using it as onsite fuel or for another beneficial purpose, or injecting/reinjecting it was infeasible for technical or safety reasons. A new source is defined as a well that commenced construction, reconstruction, or modification after December 22, 2022. Further, the definition of “commenced” found within 40 CFR 60.2 applies for purposes of NSPS OOOOb. That definition states that “commenced means . . . that an owner or operator has undertaken a continuous program of construction or modification or that an owner or operator has entered into a contractual obligation to undertake and complete, within a reasonable time, a continuous program of construction or modification.”

As discussed in section XI.F.2.c of this document, the EPA believes that, with the full knowledge and understanding of the final rule, owners planning on drilling new wells in the future have the ability to plan ahead to ensure that the associated gas is routed to a sales line, used as onsite fuel or for another beneficial purpose, or injected/reinjected. However, the EPA acknowledges that new wells have commenced construction in the period between December 22, 2022, and the date of publication of this final rule, and that it is reasonable for owners and operators of such wells to have assumed that the final rule could have continued to allow the proposed allowance to routinely flare the associated gas or route it to a control with an infeasibility determination and certification. The EPA concludes that for wells in this situation, it is appropriate to allow the associated gas to be routinely routed to a flare or control device with a determination and certification that it is technically infeasible to route the associated gas to a sales line, use it as onsite fuel or for another beneficial purpose, or inject/reinject it. The EPA encourages owners and operators of these sources to continue to seek opportunities to route the associated gas to a sales line, use it as onsite fuel or for another beneficial purpose, or inject/reinject it. These methods will not only eliminate the environmental impacts of routine flaring but will also significantly reduce the compliance burden on the owners and operators. Therefore, the final rule allows sources that have made the requisite determination and certification to route the associated gas to a flare or control device that achieves a 95.0 percent reduction in VOC and methane emissions for those wells for which construction was commenced between December 22, 2022, and the effective date of the final rule, which is May 7, 2024. This is only allowed with a demonstration and certification that it is technically infeasible to route the associated gas to a sales line, use it as onsite fuel or for another beneficial purpose, or inject/reinject it. This demonstration and certification must then be renewed annually. See section XI.F.2.g of this document for a discussion of comments received on the infeasibility determination and certification process and the requirements contained in the final rule.

The EPA recognizes that existing sources that undergo reconstruction or modification and thus become new sources also face different circumstances than new wells for which construction commences with full knowledge of the “no routine flaring” requirement in the final rule. These wells were likely originally drilled without the expectation that the EPA would be proposing and promulgating requirements that would require the routing of associated gas to a sales line, using it as onsite fuel or for another beneficial purpose, or injecting/reinjecting it as required by the final rule. The location of these existing wells that are undergoing reconstruction or modification is established and the owner or operator does not have the ability to move the well to allow connection more easily to a sales line, to inject into another well, or perhaps to utilize any other option. Therefore, the EPA concluded that it is appropriate to allow wells reconstructed or modified after December 22, 2022, to routinely flare associated gas or route it to control with a technical infeasibility determination and certification. This demonstration and certification must then be renewed annually.

Finally, the EPA acknowledges that owners and operators could have initiated the planning stages of a new well based on the December 2022 Supplemental Proposal even though they may not have specifically undertaken the activities that meet the definition of “commenced construction.” Therefore, owners and operators may have made preliminary plans assuming that flaring or routing to control would be allowed with a determination that it is technically infeasible to route the associated gas to a sales line, use it as onsite fuel or for another beneficial purpose, or inject/reinject it. The final rule allows sources that commence construction within a certain period after the effective date of the rule to routinely route the associated gas to a flare or to a control device for a short period, after which they are required to route the associated gas to a sales line, use it as onsite fuel or for another beneficial purpose, or inject/reinject it. This will allow owners and operators to proceed with plans, but also not allow routine flaring or routing to control for an extended period. Specifically, the final rule allows wells for which construction commences between May 7, 2024 and May 7, 2026 to route the associated gas to a flare or to a control device that achieves a 95.0 percent reduction in VOC and methane emissions, with the proper demonstration of technical infeasibility, until May 7, 2026. Routine flaring for these sources is only allowed with a demonstration and certification that it is technically infeasible to route the associated gas to a sales line, use it as onsite fuel or for another beneficial purpose, or inject/reinject it. This demonstration and certification must then be renewed annually. After May 7, 2026, these sources will no longer be able to routinely flare associated gas, and must route the associated gas to a sales line, use it as onsite fuel or for another beneficial purpose, or inject/reinject it. For information regarding technical infeasibility demonstrations, including examples, see section X.F.2.a.i. of this document.

e. BSER for Existing Sources

In the December 2022 Supplemental Proposal, the EPA proposed presumptive standards for associated gas from existing oil wells for the EG OOOOc that mirrored those for new sources under NSPS OOOOb. That is, EG OOOOc included four compliance options to eliminate emissions of methane from associated gas from existing oil wells. These options were: (1) recover the associated gas from the separator and route the recovered gas into a gas gathering flow line or collection system to a sales line, (2) recover the associated gas from the separator and use the recovered gas as an onsite fuel source, (3) recover the associated gas from the separator and use the recovered gas for another useful purpose that a purchased fuel or raw material would serve, or (4) recover the associated gas from the separator and reinject the recovered gas into the well or inject the recovered gas into another well for enhanced oil recovery. Associated gas was allowed to be routed to a flare or other control device if the owner or operator demonstrated that all four options were infeasible due to technical or safety reasons and if that demonstration is approved by a certified professional engineer or other qualified individual.

Comment: One commenter suggested that there was a fundamental flaw in the EPA's process that has resulted in a misguided BSER determination for existing sources that effectively regulates existing sources the same as new and modified sources. Another commenter claimed that the EPA's recurring conclusion that designated facilities under the EG should be the same as affected facilities under the NSPS did not recognize the differences between new and existing sources.

Response: The EPA generally agrees with the commenters that consideration must be given to any meaningful differences between new and existing sources in determining the respective BSER. The EPA proposed that routing the associated gas from existing wells to a sales line was an adequately demonstrated method of emissions reduction and the costs were reasonable. We also determined that the other equivalent compliance options also were appropriate for existing sources (we did not identify any limitations that would universally inhibit use of the alternatives for existing sources). We recognized that there could be situations where it was infeasible to comply with one of these options, so the proposed presumptive standards in EG OOOOc included the allowance to routinely flare the associated gas or route it to control if it was demonstrated and certified that the earlier listed four alternatives were infeasible due to technical or safety reasons.

As discussed in section XI.F.2.c of this document, the final rule will phase out the option for new sources to routinely route the associated gas to a flare or control device. In addition, numerous comments were submitted regarding considerations related to wells that produce low levels of associated gas. In light of the changes to the NSPS and comments received specific to existing sources of associated gas, the EPA reevaluated the BSER for existing sources. This revised BSER analysis for existing sources recognizes that, unlike new sources, existing sources may not have taken into account distance to a gas line when choosing their location and cannot readily do so now.

Comment: Commenters believed that the EPA needs to maintain flaring as an option for wells with little associated gas. They maintained that the gas production rate is too low to be able to justify the expense of routing to a sales line or even investing in the equipment to inject the gas back into the reservoir. Many times, the gas production rate is too low to be able to reliably operate an engine to produce power to operate surface equipment. They added that low production wells need to have the option to flare the gas as an environmentally acceptable option. The commenters believed that eliminating this option would be an unnecessary burden on small businesses.

The commenters pointed out that much of the associated gas from low production wells does not meet the requirements to be sold on an interstate pipeline system. The gas may require water, nitrogen, CO₂, and heavier hydrocarbons (ethane, propane, butane, pentane, and hexane) to be removed prior to its being sold into the gas market. The cost to make the gas “pipeline spec” usually exceeds the benefit of selling the gas on the pipeline. The commenters provided that this is another example where low production wells should be exempt from the proposed regulation.

Another commenter explained that, for many of their existing wells, no sales line is readily available, and even if one was available, the volume of associated gas may be too low to reach a sales line. The commenter recommended that the EPA reconsider this requirement for existing well sites, in recognition that the infrastructure is unlikely to be present to make such a requirement feasible.

Yet another commenter recommended that the EPA maintain an exemption for low production wells. The commenter explained that many of the low production wells operate with low pressure and low gas-to-oil ratios, so the PTE is significantly less than the PTE for higher-production wells that were recently drilled.

Response: As discussed in section XI.F.2.b of this document, the EPA obtained data and performed a cost analysis of collecting the associated gas and routing it to a sales line for a representative new well. As discussed, this representative new well had methane emissions of 343.6 tpy. In response to the comments regarding low associated gas production wells, the EPA performed an analysis for varying baseline emissions levels and distances to the gathering system. Specifically, the EPA evaluated the costs of routing associated gas to a sales line for distances up to 5 miles using a 4-inch pipe. The results of this analysis are provided in table 24.

Based on the results of this analysis, the EPA decided it was appropriate to separate existing oil wells with associated gas into two subcategories. For wells with 40 tpy of methane emissions, the cost effectiveness of routing to sales was considered reasonable at distances in a range of about 3 miles. We assume that the methane emissions are equivalent to the amount of methane contained in the associated gas. Therefore, the two subcategories are those with associated gas that contains 40 tpy or less methane and those that contain greater than 40 tpy methane. The EPA then developed BSER separately for these two subcategories.

i. BSER for the Subcategory of Wells With Associated Gas Containing 40 tpy or Less Methane

For wells that produce 40 tpy or less of associated methane gas, the analysis shows that, depending on the distance from the well to the gathering system, it could sometimes be cost-effective to route the associated gas to a sales line, and sometimes not. Assuming that there is an existing flare or control device onsite that could accept the associated gas, the cost to direct the associated gas into the flare would be minimal (approximately $6,100 capital cost, with an annual cost of $670). The cost effectiveness of routing to an existing flare for an associated gas well where the associated gas contains 40 tpy of methane is $18 per ton of methane, which is well within the range that the EPA has considered reasonable. In fact, the cost effectiveness for wells with 1 tpy of methane ($915/ton) is still reasonable. For the installation of a new flare, the cost effectiveness for a well where the associated gas contains 40 tpy methane is $1,758 per ton of methane, which is also considered reasonable. Considering that routing associated gas to a flare or control device is an adequately demonstrated method and considering this cost effectiveness leads the EPA to conclude that BSER to reduce the methane emissions from associated gas from existing oil wells where the associated gas contains 40 tpy or less of methane is routing to a flare. This outcome is consistent with the recommendations made by the commenters.

Comment: One commenter stated that repeated, onerous technical infeasibility analyses and detailed recordkeeping should be eliminated in the final rule for wells with low associated gas production.

Response: Because the EPA has determined that BSER for this subcategory of existing sources is routing to a flare or control device, the final model rule does not include a requirement to demonstrate technical infeasibility for wells with associated gas containing 40 tpy or less of methane. The presumptive standard allows sources in this subcategory to routinely flare without needing to make a demonstration of technical infeasibility. However, the final presumptive standard does include the requirement to calculate and document the methane content of associated gas using the GOR. The calculation is based on a simplified version of the methodology in subpart W of the GHGRP.

Note that under the presumptive standard in the final EG, owners and operators of these low associated gas production wells are allowed to route the associated gas to a sales line, use it as onsite fuel or for another beneficial purpose, or inject/reinject it. In fact, the EPA encourages this option where possible. If a source elects to comply with one of these options, the presumptive standard would not require that source to comply with the requirement to calculate the annual methane content of the associated gas.

Comment: One commenter stated that many older, existing well sites in the Midland Basin do not have flares onsite, and it would present a significant capital expense to add a flare or similar control device at each existing well site. Another commenter stated that “for many conventional oil wells in Pennsylvania and New York, a gas sales line is not reasonably available. The “associated gas” produced at these conventional oil and gas well sites would not be sufficient to sustain a flare, much less justify the changes and capital expenditures needed to attempt to use the gas onsite. The commenter indicated that the EPA must expressly allow Pennsylvania and New York conventional oil producers to vent the small volumes of “associated gas,” which the commenters contend is the only safe and environmentally sound method of dealing with associated gas at some Pennsylvania conventional oil wells. The first commenter stated that the EPA should consider the remaining useful life of these existing sources, as required by the CAA.

Response: The EPA acknowledges these comments and understands that certain situations exist where the methane content in the associated gas is low and there is not a flare or control device onsite. The EPA also recognizes that the cost of installing a new flare or control device solely to reduce the methane emissions from the associated gas could be above what is typically considered reasonable by the EPA for wells with very low levels of methane. Both commenters cite instances where the wells are older and located in specific geographic locations. We conclude that these situations are most likely to occur for older wells where the wells are approaching the end of their useful lives. The EPA also believes that the wells discussed by comments do not represent the majority of designated facilities across the country. Therefore, the EPA did not elect to further subcategorize wells with 40 tpy or less associated gas methane into those sites with and without existing control devices. First, the EPA believes that many of these sites likely have existing control devices already onsite that could accommodate the associated gas. The EPA is aware that several states, including New Mexico, North Dakota, and Texas, have regulations that require control devices in certain situations that are relevant here. Second, we believe that the particular sites discussed by commenters could be candidates for states to examine under the RULOF framework of 40 CFR part 60, subpart Ba, when states are developing their state plans in accordance with these final EG in 40 CFR part 60, subpart OOOOc. States can consider the RULOF-specific situations at the low associated gas production wells that do not have flares or other control devices onsite to possibly apply a standard of performance less stringent than the presumptive standard in this EG consistent with the EPA's implementing regulations. Further, the EPA acknowledges that the Agency did not assess costs for existing wells that are located more than 5 miles away from a gathering system, and states may wish to examine the possibility of invoking RULOF for situations where a well with low levels of associated gas is located a far distance away from a gathering system and cannot otherwise comply with the alternatives included in the presumptive standard.

ii. BSER for the Subcategory of Wells With Associated Gas Containing Greater Than 40 tpy Methane

As discussed for new sources, routing associated gas to a sales line is an adequately demonstrated method for reducing methane emissions. As shown in table 23, the cost effectiveness of routing the gas to a sales line for wells with associated gas containing greater than 40 tpy methane is at levels considered reasonable by the EPA, especially in situations where the well is relatively near the gathering system. Therefore, the EPA determined that BSER for this subcategory is routing the associated gas to a sales line. As with new sources, the EPA believes that the other options that achieve the same level of emissions reduction should be allowed.

As discussed for modified and reconstructed sources, the EPA recognizes that existing sources were likely originally drilled without the expectation that the EPA would issue these EG which include a presumptive standard of routing the associated gas to a sales line, using it as onsite fuel or for another beneficial purpose, or injecting/reinjecting it. The location of these existing wells is established, and the owner or operator may not have the ability to move the well to allow a closer connection to a sales line, to inject into another well, or perhaps to utilize any other option. Therefore, the EPA concluded that it is appropriate to allow existing wells with greater than 40 tpy methane to routinely flare associated gas or route it to control with a technical infeasibility determination and certification which is renewed annually.

The final presumptive standards for existing wells with associated gas containing greater than 40 tpy methane are to reduce or eliminate emissions of methane by: (1) Recovering the associated gas from the separator and routing the recovered gas into a gas gathering flow line or collection system to a sales line, (2) recovering the associated gas from the separator and using the recovered gas as an onsite fuel source, (3) recovering the associated gas from the separator and using the recovered gas for another useful purpose that a purchased fuel or raw material would serve, or (4) recovering the associated gas from the separator and reinjecting the recovered gas into the well or injecting the recovered gas into another well. In addition, the final presumptive standards for this subcategory allow the associated gas to routinely be routed to a flare or control device that reduces methane and VOC emissions by at least 95.0 percent if annual demonstrations are made that it is technically infeasible to route the associated gas to a sales line, use it as onsite fuel or for another beneficial purpose, or inject/reinject it and the determination is certified by a professional engineer or another qualified individual with expertise in the uses of associated gas. See section XI.F.2.g of this document related to the infeasibility determination and certification.

Comment: One commenter stated that the EPA failed to understand the implications of inherent production depletion on the economics and emissions from smaller wells. The commenter asserted that there are fundamental factors that are not adequately considered in the EPA assessments, and that, as oil and natural gas wells undergo their inherent depletion, the reduced volumes of production limit the amount of emissions that can be generated.

Response: The EPA understands the depletion of production over time and understands that it impacts the associated gas volume, and thus the methane contained in the associated gas. Therefore, the presumptive standard included in the final EG includes the provision that existing wells whose production is less than 40 tpy of methane upon becoming a designated facility can flare routinely without a demonstration of technical infeasibility. The EPA determined that for wells with above 40 tpy of methane it is reasonable to route the gas to a sales line or choose an equivalent alternative, or in the absence of a feasible alternative, to flare the gas. While the level of gas production may decline over time from above 40 tpy to below, the EPA considers the cost of control of the gas from designation as a designated facility producing over 40 tpy to the time of well closure to be reasonable, and considers that the cost may be mitigated by any recovery from an associated gas management technique that allows some cost savings. Further, if an owner/operator is already complying with a zero-emissions option, then they should be able to continue to comply with that option cost-effectively, even if their production declines, as they have already made the investment.

f. Temporary Flaring/Venting

Comment: A number of comments were received on the topic of temporary flaring and venting. Commenters from across the spectrum (industry, state agencies, environmental organizations) agree that there are extenuating circumstances beyond the reasonable control of the operator that can result in the inability to exercise the primary use option. Further, there is agreement that flaring should be allowed in these circumstances. Commenters encouraged the EPA to distinguish between “routine” and “non-routine” flaring events.

In the December 2022 Supplemental Proposal, we proposed “to require that if owners and operators anticipate that there may be interruptions in the ability to route the associated gas to a sales line or to use it for another beneficial purpose, they must provide a technical or safety demonstration in their annual report and install and operate a control device that achieves the required reduction during these temporary periods” (p. 74780).

While there was agreement among the commenters on the need to allow temporary flaring, there was also universal objection to this proposed requirement for technical or safety demonstrations to justify flaring. One commenter urged the EPA to abandon the broad, unclear technical infeasibility exemption. Another recommended the replacement of the “technical infeasibility” exemption with clearly delineated circumstances for temporary flaring. Another contended that, for those situations where the gas from the well is connected to a sales line and there are instances where the gas needs to be routed intermittently to a control device for equipment maintenance, repairs, emergencies, or other similar situations, this type of flaring should not have to undergo repeated, onerous infeasibility determinations and detailed recordkeeping requirements. Another commenter requested that for wells where the operator has designed and configured the separator to recover and sell or beneficially use associated gas, the EPA remove the requirement to provide an infeasibility or safety justification for controlling associated gas when the primary means of disposition is temporarily unavailable. Another commenter explained that when a facility is designed with a certain configuration for handling the disposition of associated gas, it is unreasonable to expect facilities to design for multiple uses based on emerging technologies before they can resort to flaring, especially during these short, intermittent periods. They did not support making technical or safety demonstrations where disruptions or interruptions in the gas gathering infrastructure result in the need to route the associated gas to a control device for temporary periods. One commenter suggested that, rather than an infeasibility determination being required for every instance, a one-time infeasibility determination should suffice.

Commenters recommended that, rather than requiring an infeasibility demonstration for specific instances, the EPA delineate instances in the rule where temporary flaring is allowed. Commenters generally indicated that flaring should be allowed during upset conditions, which one commenter defined as emergency circumstances outside of the control of an operator that can interrupt its ability to comply with the standard. Commenters also provided specific situations, including the following:

• Due to a temporary, unplanned loss of connection to, or ability to route gas to, a gathering system.
• During the commissioning of pipelines, equipment, or facilities.
• When the natural gas does not meet pipeline specifications.
• Temporary failure of equipment.
• During startup and shutdown activities.
• During maintenance activities.
• During construction activities and facility modifications.
• During well testing.

In addition to suggesting that the EPA delineate specific instances when temporary flaring is allowed, commenters recommended that the EPA establish clear time limitations during which the flaring is permitted.

In addition, one commenter identified circumstances where venting may be warranted. The commenter acknowledged that venting may be necessary for safety. In addition, they added that operators may need to vent for a very brief period during downhole monitoring activities, namely when monitoring the downhole pressure during bradenhead monitoring and packer leakage tests.

Commenters stressed that state rules, specifically in Colorado and New Mexico, allow operators to flare or vent gas for short periods of time during upset conditions or emergencies, including temporary unavailability of access to a gathering line. Further, both states list specific instances and time frames when flaring is allowed. Examples cited by the commenters include the following.

A commenter discussed circumstances where the EPA may consider exemptions from its capture requirements in which flaring is authorized. One circumstance that may give rise to an operator's need to flare on a temporary basis is the commissioning of pipelines, equipment, or facilities. The commenter provides that New Mexico allows operators to flare temporarily during these circumstances, and even then “only for as long as necessary to purge introduced impurities.” An operator may need to flare temporarily when it is first connecting to a pipeline that has just been constructed if the pipeline was cleaned out with substances that the midstream operator does not want in the gas.

The commenters report that both Colorado and New Mexico allow operators to vent or flare during bradenhead monitoring. Colorado limits bradenhead monitoring to 30 minutes. New Mexico also allows operators to flare or vent during packer leakage tests.

Commenters stated that New Mexico allows for temporary venting or flaring during an emergency. An emergency means “a temporary, infrequent, and unavoidable event in which the loss of natural gas is uncontrollable or necessary to avoid a risk of an immediate and substantial adverse impact on safety, public health, or the environment” other than in certain exceptions. One such exception is “venting or flaring of natural gas for more than 8 hours after notification that is caused by an emergency, an unscheduled maintenance, or a malfunction of a natural gas gathering system.” In other words, an upstream operator may vent or flare during a temporary, infrequent, and unavoidable event involving loss of connection to a sales line provided the midstream operator notifies the producer of the disruption to the operator of the sales line. However, an upstream operator cannot vent longer than 8 hours in this circumstance.

One commenter provided that both Colorado and New Mexico allow operators to flare or vent gas for a short period of time during upset conditions or emergencies which include temporary unavailability of access to a gathering line. The commenter explained that the Colorado rules provide a concise, clear definition of upset condition combined with a limit on the amount of time an operator may flare or vent during such circumstances. Colorado allows operators to vent or flare for up to 24 cumulative hours during an upset condition while New Mexico allows operators to vent or flare for up to 8 hours during an emergency. Loss of a connection to a pipeline qualifies as an upset condition under the Colorado rules and an emergency under the New Mexico rules.

The commenter added that New Mexico allows for temporary venting or flaring during an emergency. An emergency means “a temporary, infrequent, and unavoidable event in which the loss of natural gas is uncontrollable or necessary to avoid a risk of an immediate and substantial adverse impact on safety, public health, or the environment” other than in certain exceptions.

Response: As discussed in section XI.F.2.b of this document, the representative well and the BSER analysis are focused on associated gas emissions during routine operations. We appreciate the information and insights provided by the commenters, and overall we agree with the recommendations.

First, we recognize that there are circumstances that could arise that are beyond the control of the owner or operator and that could result in the temporary inability to comply with the standards, and we do not believe it is appropriate to require the shut-in of the well in such instances.

We agree with the commenters that the proposed requirement to demonstrate infeasibility based on technical or safety reasons for each of these temporary instances is not the most efficient solution. Rather, in the final rule, we have incorporated an approach similar to requirements adopted by New Mexico and Colorado. The final rule identifies specific circumstances in which temporary flaring or venting are allowed. The final rule also includes maximum timeframes for each circumstance. Following are the specifics included in the final rule. Temporary flaring (or routing to a control device to achieve 95 percent reduction) is allowed:

• For up to 24 hours during a deviation caused by a malfunction.
• For up to 72 hours during repair, maintenance including blowdowns, a packer leakage test, a production test, or commissioning.
• For up to 30 days during temporary interruption in service from the gathering or pipeline system.
• For up to 72 hours if associated gas does not meet pipeline specifications.

While temporary flaring or routing to a control device is allowed in these situations, it is important to ensure that, with the additional gas that is being routed to the flare or control device during this temporary period, the flare or control device continues to operate properly. Therefore, the final rule includes the requirement that the owner or operator demonstrate that applicable flare or control device requirements are being met during the temporary period when the associated gas is routed to the control.

Comment: One commenter supported the use of temporary control devices for situations when the associated gas could not be routed to a sales line, used as onsite fuel or for another beneficial purpose, or injected/reinjected. The commenter explains that some sites may have permanent control devices for these scenarios. However, temporary controls can be used to minimize emissions during planned maintenance, startup, and shutdown activities. Emissions from these temporary controls are permitted as an alternate operating scenario, as a part of normal operations. Another commenter supported flaring the gas by using a permanent or temporary control device that achieves 95 percent efficiency during periods of time when the associated gas is routed to the control device.

Response: In the December 2022 Supplemental Proposal, we stated that we anticipated that a control device used to reduce emissions during these temporary periods “would need to be permanently installed.” However, we specifically requested comment on whether the use of temporary controls could also serve this purpose. Commenters responded that such control devices would likely be permanent controls, albeit control systems that are present for reasons other than providing redundant control for associated gas.

The EPA has determined that it is not necessary that a control device be permanently installed for these situations. However, if a temporary flare or control device is used, it is required to meet the same control device requirements as a permanent control device.

In addition to the allowance for temporary flaring or routing to a control device, the final rule allows venting in the following circumstances and durations:

• For up to 12 hours to protect the safety of personnel.
• For up to 30 minutes during bradenhead monitoring.
• For up to 30 minutes during a packer leakage test.

The final rule requires that detailed records be kept of each of these venting situations.

g. Infeasibility Demonstration and Certification

The proposed NSPS OOOOb regulation and EG OOOOc presumptive standards both included the allowance that associated gas could be routed to a flare or control device after a demonstration and certification that it is infeasible to route the associated gas to a sales line or to comply with the other options. The December 2022 Supplemental Proposal required that this demonstration include a detailed analysis documenting and certifying the technical or safety infeasibility for all options. It also listed specific types of other useful purposes that owners and operators were required to address, specifically methane pyrolysis, compression of gas for transport to another facility, conversion of gas to liquid, and production of liquified natural gas. The proposal required that this demonstration be certified by a professional engineer or another qualified individual with expertise in the uses of associated gas.

As discussed in section XI.F.2.f of this document, there were many comments submitted that objected to the proposal to require a demonstration of infeasibility based on technical or safety reasons for temporary use of a flare or control device in instances when the primary option ( e.g., routing the associated gas to a sales line, using it as onsite fuel or for another beneficial purpose, or injecting/reinjecting it) is unavailable. Rather they suggested that the rule and presumptive standards include specific instances when such temporary flaring or routing to control is allowed. As also discussed in section XI.F.2.f of this document, the final rule includes such a list of specific circumstances. Therefore, the infeasibility demonstration and certification provisions in the final rule are applicable to situations where routing the associated gas to a sales line, using it as onsite fuel or for another beneficial purpose, or injecting/reinjecting it are not feasible and routing to a flare or control device is routine.

On a related topic, one commenter suggested that safety concerns are by their nature temporary and would never give rise to the need to flare indefinitely. The commenter suggested that the EPA should therefore require that any safety-related flaring cease when the safety concern no longer exists. The EPA agrees that the need to flare or route to control for safety reasons is a temporary issue, and not a reason that would warrant long-term routine flaring. Therefore, the final rule allows routine flaring or routing to control based only on technical infeasibility, and not safety.

Comment: Commenters suggested that the EPA not require consideration of predetermined beneficial uses for oil well associated gas, and, if the EPA retains such a list, any included beneficial use must be commercially viable. One commenter stated that the EPA proposed that operators must certify that use of “recovered gas for another useful purpose that a purchased fuel or raw material would serve” is not feasible “due to technical or safety reasons” before the operator may control associated gas onsite. They added that the EPA proposed that the feasibility analysis must include consideration of using gas for “methane pyrolysis, compressing the gas for transport to another facility, conversion of gas to liquid, and the production of liquified natural gas.” The commenter fully supports the beneficial use of natural gas where reasonably feasible and cost-effective and further supports development of additional technologies that would provide a broader range of potential beneficial uses. The commenter believed that the EPA's inclusion of a predetermined list of uses suggests that the EPA has determined each of these beneficial uses to be technically feasible, commercially available, and appropriately included as part of the associated gas BSER. The commenter contends that the EPA, however, has provided no support for this apparent determination. Accordingly, the commenter requested that the EPA remove this list of beneficial uses. Further, to the extent the EPA maintains such a list of beneficial uses, the commenter requested that the EPA remove any unproven “emerging technologies.” The commenter stated that CAA section 110(j) provides the appropriate pathway for sources to evaluate emerging technologies to meet NSPS. According to the commenter, requiring evaluation of unproven emerging technologies sidesteps both the BSER demonstration and the CAA section 110(j) process in violation of the CAA. Another commenter, a state agency, supported emerging technologies as potential methods for controlling emissions from oil and gas facilities and recommended that the rules allow the use of emerging technologies as a recognized method of achieving a beneficial use for associated gas. The commenter reported that some companies use the associated gas as fuel for electric generating units or compress the gas and send it to another site for processing. The commenter believed that useful purpose should include, but not be limited to, uses or purposes that a purchased fuel or raw material would serve. The commenter also believed that useful purpose should not be explicitly defined in the rule language, and that the owner or operator can provide a demonstration or certification that they meet this criterion. Due to the unpredictable nature of technological advancement, the commenter believed it would be shortsighted for the EPA to limit this aspect of the rule to only narrowly defined or specified processes or technologies. Certain technologies for reducing methane and other GHG emissions, such as gas compression for offsite transport, can also result in collateral emissions of other regulated pollutants which are subject to the national ambient air quality standards (NAAQS).

Response: The EPA reviewed these comments and concluded that the regulation should not include a specific list of other beneficial uses, for the reasons pointed out by the commenters. However, as discussed in section X.F.2.a of this document, it is the responsibility of the owner and operator, along with the qualified professional engineer or other qualified personnel performing the evaluation, to conduct due diligence by ensuring that the list of options evaluated be comprehensive and address commercially viable solutions.

Comment: One commenter argued that the EPA must limit the exemption by clearly delineating specific “technical” reasons that would justify flaring in lieu of the four gas recovery options. They stated that the EPA must require operators to demonstrate the physical impossibility of each of the gas recovery options to claim the exemption to flare. The commenter provided potential physical impossibility demonstrations for each abatement method.

Response: The EPA believes that including specific criteria in the rule would be short-sighted and potentially eliminate legitimate reasons that an option is technically infeasible. As discussed in section X.F.2.a.1 of this document, the EPA generally characterizes acceptable reasons in the general categories of physically, logistically, or technically infeasible. Examples are provided in that section.

Comment: One commenter suggested that the BSER opt-out should include economic factors in addition to technical feasibility. The commenter reported that the EPA concedes that it is proposing multiple regulatory requirements whose implementation would be so burdensome that they would be “technically infeasible” for some set of affected facilities. According to the commenter, the EPA thus gives affected facilities the ability to “opt out” of the performance standard if the affected facility can show that compliance with the performance standard would be infeasible for technical or safety reasons. The commenter contends that “technically infeasible” is a misnomer and that the EPA should explicitly include economic factors in addition to a technical feasibility analysis. The commenter stated that, instead of conflating technical feasibility and economic considerations, the EPA in its final rule should transparently state that economic factors must be part of an affected facility's ability to opt out of the regulatory requirement. A state agency commenter asked what factors or thresholds should be considered if economic feasibility needs to be assessed.

Response: The EPA disagrees that economic feasibility is a valid criterion on which to allow routine flaring or routing to control as part of the standard. As shown in Table 23, the EPA has determined that the costs associated with the control option determined to be BSER (routing to a sales line) are reasonable. Put another way, the EPA has already considered costs when setting the standard. As such, there is no reason to allow for the type of “economic feasibility” showing that commenters are requesting. Further, to include economic feasibility as a criterion would necessarily take into account many aspects of plant operation that are not related to the cost of the control option (the BSER). The approach that commenters suggest could result in a situation where wells that are operating close to the margin due to inefficiencies and poor operation obtain an allowance to routinely flare while more efficiently operated wells do not. The EPA does not believe that allowing for this type of outcome is appropriate because it would unfairly provide preferential treatment to certain owners and operators based solely on the fact that their operation is less efficient. Lastly, allowing the type of economic feasibility that commenters are asking for would necessarily entail a certain degree of subjectivity that the EPA does not find to be appropriate in this context. The EPA believes that it would be inappropriate to establish such thresholds in this context and does not find it necessary.

Comment: One commenter points out that the EPA proposal contemplated four abatement alternatives to deal with associated gas from oil wells. While each alternative has its pros and cons, the alternatives are also necessarily based upon, to some extent, well and/or lease economics. The predominant methodology used by regulators, including the EPA, and operators, is to evaluate these economic decisions on the gas production only and its prevailing pricing. The commenter held that the entire well/lease revenue stream—including revenue from oil—needed to be considered, especially if the decision to get to a sales line is the question. The commenter stated that considering gas revenue only actually promotes waste and negative environmental impact. Therefore, according to the commenter, the EPA rejects economic viability as a criterion to be considered in the infeasibility determination that would allow routine flaring.

Response: The EPA agrees with the premise of the comment that the standards for associated gas should not be limited to those options whose cost can be covered by the recovery of associated gas. The EPA's BSER analysis acknowledges that cost recovery through the sale or use of associated gas will contribute to the cost effectiveness of some methods of reducing emissions from associated gas, but the EPA did not make the ability to recover the gas for sale the defining criteria to select BSER or the equivalent alternatives. For example, an operator who chooses to inject the gas into the well or another well may not derive any financial benefit to injecting the gas in the form of greater oil production, but injecting the gas is acceptable in lieu of routing to a sales line because it achieves emissions reductions equivalent to those for routing the associated gas to a sales line.

Comment: One commenter believed that the exemption for technical infeasibility presents enforcement challenges. While an operator's demonstration of technical infeasibility must be signed and certified as to its truth, accuracy, and completeness, the commenter provided that there is no requirement that the EPA review and approve this demonstration prior to an operator's flaring. Rather, the proposal only required that operators retain records of the certified demonstration and provide them to the EPA as part of annual reporting. The commenter indicated that this lack of requirement raises the possibility that flaring will occur in the absence of a full, accurate, complete, or otherwise adequate demonstration. The commenter indicated that in order for the EPA to identify any problems or shortcomings in the certified demonstration, the EPA must review the operator's documentation, but this review will necessarily occur after an operator has flared, potentially for a considerable amount of time. The commenter states that this opens the door to extended periods of flaring in violation of the rules. Another commenter asserted that the technical infeasibility exemption places a significant compliance monitoring burden on the EPA, or on states with delegated air quality programs.

Response: The EPA does not agree with these commenters. As explained above, the final NSPS OOOOb and EG OOOOc include provisions that allow owners and operators to make certain technical infeasibility demonstrations in limited circumstances. To the extent that an owner or operator makes such a showing, the EPA believes that the requirement to submit the demonstration and certification of infeasibility in the annual report provides the opportunity for the EPA and/or state agency to conduct a review. In the event that the owner or operator submits an inadequate or fraudulent determination, or no determination at all when they should have, they could be subject to penalties. In addition, the professional engineer or other individual who certified the demonstration could be subject to penalties, including criminal charges. Therefore, no changes were made to the proposed requirements for submission of the demonstrations and certifications.

Comment: With respect to the certification process, one commenter recommended that the EPA require certification by an independent third party. The commenter pointed out that the EPA proposed to allow certification by either a professional engineer or a “qualified individual with expertise in the uses of associated gas.” Notably, per the EPA's proposal, an operator could use an in-house engineer or other qualified individual, such as a contractor. The commenter noted that there is no requirement that the individual be independent from the operator. Certification by an independent third party, rather than a professional engineer or a “qualified individual with expertise in the uses of associated gas,” either of whom could be an in-house individual or a person with significant ties to the company, will enhance the credibility and reliability of the report. Certification by an independent third party of all demonstrations seeking a flaring exception is necessary to ensure a robust, complete, and accurate demonstration of the reasons underlying the flaring request.

Response: The EPA does not agree that it is necessary for the certifier to be an independent third party. In many cases, a person most knowledgeable about the well characteristics and specifics of the operation may be someone employed by the company. While the EPA understands the concern raised by the commenter about the certification being made entirely “in-house,” the EPA points out the severe penalties and repercussions that could occur for both the owner/operator and the certifier, as discussed here.

Comment: The commenter requested that the EPA further clarify that both the certifier and the owner/operator may be subject to penalties for submission of a fraudulent or significantly flawed certification. The commenter notes that this clarification is consistent with the EPA's proposal for pneumatic pumps. The EPA proposed to include a technical infeasibility exemption from the zero-emissions pneumatic pump standard, provided an operator submits a demonstration certified by a qualified professional engineer or in-house engineer with relevant experience. The EPA notes that it “is committed to ensuring that this technical infeasibility provision is not abused or used as a loophole . . . ,” pointing to the potential for enforcement actions to be levied against both the owner/operator and the certifier upon submission of a “fraudulent, or significantly flawed” certification. The commenter urges the EPA to clarify that this same potential penalty is applicable to the submission of “fraudulent, or significantly flawed” certifications in the context of associated gas at the affected well facility, if the EPA retains the technical infeasibility exemption.

Response: The EPA agrees with the commenter. Flaws in a certified engineering analysis may result in an exception being inapplicable and a related enforceable violation of the standards. Fraudulent or significantly flawed certifications may result in both civil and criminal liability and penalties for the owner, operator, and the person that makes the certification.

Comment: One commenter suggested that operators seeking to routinely flare must submit a thorough analysis and engineering certification comparable to the initial certification each year. The commenter recommended that this demonstration include the same information as the initial demonstration, namely a detailed analysis documenting the technical infeasibility or safety reasons for the infeasibility and an explanation as to why none of the four gas recovery options are technically feasible or safe. Each annual demonstration must be certified.

Response: The EPA agrees with this comment and has clarified that the exemption is only valid for a 1-year period and that a demonstration and certification must be conducted each year to continue to flare or route to control.

3. Gas Well Liquids Unloading Operations

In section X.F.3 of this document, the final NSPS OOOOb and EG OOOOc requirements for gas well liquids unloading operations are summarized. The BSER analysis is unchanged from what was presented in the November 2021 Proposal (see 86 FR 63211–14, section XII.D: Proposed Standards for Well Liquids Unloading Operations). Two regulatory approaches were proposed in the November 2021 Proposal. As discussed in the December 2022 Supplemental Proposal, the EPA considered the comments submitted and revised the proposed requirements. Details of these comments, the EPA's responses, and the rationale for the supplemental proposal are provided in the December 2022 Supplemental Proposal Federal Register preamble. As discussed in section X.F.1 of this preamble, in the December 2022 Supplemental Proposal, the EPA proposed to define the “affected facility” as a single well. Further, the EPA proposed the “modification” definition to apply to a single well that undergoes hydraulic fracturing or refracturing. Significant comments were received on the December 2022 Supplemental Proposal on the following topics: (1) the EPA's proposed zero-emissions standard, and (2) the EPA's proposed recordkeeping and reporting requirements. For each of these topics, a summary of the proposed rule, the comments, the EPA responses, and changes made in the final rule (if applicable), are discussed as follows. These comments and the EPA's responses to these comments would apply to the standards proposed in both the NSPS OOOOb and EG OOOOc because the same standards apply for both new and existing sources. The EPA's full response to comments on the November 2021 Proposal and December 2022 Supplemental Proposal, including any comments not discussed in this preamble, can be found in the EPA's RTC document for the final rule.

a. Zero-Emissions Standard

In the December 2022 Supplemental Proposal, the EPA proposed regulatory text specifying that all gas well liquids unloading operations would be subject to the regulatory requirements. The BSER proposed was to employ techniques or technologies that eliminate methane and VOC emissions. Where meeting the zero-emissions standard is infeasible due to technical or safety reasons, the EPA proposed to require the employment of best management practices to minimize methane and VOC emissions during well liquids unloading operations to the extent possible.

The December 2022 Supplemental Proposal, however, specifically requested further comment and additional information on an alternative approach to applicability, where the standards for gas well liquids unloading would only apply to well liquids unloading operations that result in vented emissions.

Comment: Several commenters opposed the EPA's proposed zero-emissions standard or asserted that the EPA should only regulate unloading operations that vent emissions.

Another commenter stated that the BSER must be technically feasible for the source category. The commenter provided a brief overview of the proposed standard under NSPS OOOOb that requires owners or operators to perform liquids unloading with zero methane or VOC emissions (86 FR 63179). The commenter mentioned that the proposed standard is based on a determination that non-emitting techniques constitute the BSER for these sources. At the same time, the commenter pointed out that the EPA acknowledged that non-emitting techniques are not always feasible or safe and that the EPA provides alternative standards to cover those situations.

In general, the commenter supported this approach as a practical matter and agreed that non-emitting measures and methods should be used where they are technically feasible and cost-effective. The commenter highlighted that the EPA rightly understands that non-emitting approaches are not always practicable and that imposing an absolute requirement would constitute an unwarranted prohibition on necessary operations, such as liquids unloading, in many situations. With that in mind, the commenter believed that the proposed alternative best management practice measures are a common-sense solution.

Another commenter argued that the EPA should replace what the commenter believed was an infeasible zero-emissions standard with a requirement that the affected well liquids unloading operations minimize emissions through best management practices. The commenter stated that they have significant experience using a variety of practices to safely and effectively minimize the emissions associated with gas well liquids unloading but are concerned that those practices would not satisfy the EPA's proposed zero-emissions requirement. According to the commenter, there are many reasons why liquids may accumulate in a wellbore and require liquid unloading, some of which reasons are due to external factors not in the control of the well operator. The commenter stated that the proposed standard would necessitate a detailed review and discussion of infeasibility for each event with no benefit to emissions.

The commenter recommended that, rather than establishing the proposed zero-emissions standard with an exception for unloading with minimized emissions when zero-emissions unloading is technically infeasible, the EPA establish the use of best management practices to minimize methane and VOC emissions during liquids unloading events to the extent possible as the standard itself. The commenter warned that the program contemplated by the EPA sets an impossible compliance bar, and the commenter further reiterates that a standard to develop and use best management practices to minimize methane and VOC emissions during liquids unloading events to the extent possible will achieve the same emissions reductions while eliminating the unnecessary burdens associated with demonstrating that zero-emissions unloading is infeasible.

Another commenter asserted that the rule should only apply to venting during liquids unloading. The commenter added that industry innovated to address the environmental problem of venting during liquids unloading, and they believe that the EPA's proposal would disincentivize this innovation. The commenter explained that malfunctions of designed zero‐emissions liquids unloading events would be addressed with designed venting events, with required best management practices that minimize emissions, and with recordkeeping and reporting.

Similarly, another commenter contended that the implementation of the rule would be easier if the standards only applied to wells that vent. However, the commenter suggested that the EPA only develop emissions requirements for facilities that vent emissions, not for facilities that would only vent emissions if something goes wrong or not as planned. In these situations, the commenter recommended the EPA develop separate requirements that would apply.

One commenter requested that, with respect to the emissions standards for liquids unloading, the EPA revise the rule so that an unloading event which does not result in venting to the atmosphere is not an affected facility.

Conversely, another commenter supported the November 2021 Proposal to define affected facilities to cover all wells undergoing liquids unloading as a critical requirement to ensure that operators do not simply claim to conduct liquids unloading events with zero-emissions techniques, when venting is occurring. The commenter noted that the EPA has recognized, “under some circumstances venting could occur when a selected liquids unloading method that is designed to not vent to the atmosphere is not properly applied ( e.g., a technology malfunction or operator error).” The commenter contended that in some cases, the malfunction or error could be so great that it results in venting 100 percent of the gas intended to be captured. Because of this possibility, the commenter argued, the EPA must require recordkeeping so it is aware of these events and overall emissions, and to build an understanding of what causes these errors and how they can be prevented. The commenter recommended that the EPA finalize the December 2022 Supplemental Proposal's option 1 and require operators of all wells undergoing liquids unloading to maintain records of the number of unloading events that occur, the method used, and any venting that occurred.

Response: The December 2022 Supplemental Proposal required that all liquids unloading events employ techniques or technologies that eliminate methane and VOC emissions ( i.e., a “zero-emissions standard”). If this was not feasible for safety or technical reasons, the EPA proposed to allow for the employment of best management practices to minimize venting of emissions to the extent possible. The EPA received comments that provided arguments against the proposed zero-emissions standard. These commenters generally emphasized that liquids unloading operations vary widely and standards should only apply to events that vent to the atmosphere. While we proposed a zero-emissions standard, we recognized that not every well that undergoes liquids unloading will be able to eliminate venting.

The EPA has determined that, because of the intermittent and necessary nature of allowing for variable methods and technologies employed to unload liquids, the inability to measure emissions during events, and the often-unpredictable timing as to when owners and operators may need to vent emissions, a work practice standard is more appropriate than an emissions standard for liquids unloading operations. When evaluating whether it is appropriate to establish an emissions standard, one of the things the EPA considers is whether the application of a measurement methodology is practical due to technological or economic limitations. While emissions can be measured from an unloading event, it may not be practical for many unloading events to be directly measured ( e.g., venting may not be anticipated or planned, type of technology employed to unload liquids does not lend itself to direct measurement of emissions). This is reflected in GHGRP subpart W required measurement and calculation methodologies. While in the August 2023 GHGRP subpart W proposal, the EPA proposed that emissions from liquids unloading under GHGRP subpart W must be calculated using direct measurements (calculation method 1) at least once every 3 consecutive years for each well, the proposal would continue to allow flexibility by allowing for the use of non-measurement calculation methods to accommodate times where direct measurement is not feasible or practical. For example, GHGRP subpart W calculation method 1 includes direct measurements, and methods 2 and 3 are non-measurement calculation methods. A very small percentage of events reported to the GHGRP (less than 3 percent for years 2015 to 2019) for liquids unloading events were based on calculation method 1.

The EPA also agrees that, by requiring that the proposed best management practices be implemented for liquids unloading events that vent, the same emissions reductions would be achieved, while eliminating the requirement for an owner or operator to have to document why it is infeasible to utilize a non-venting method due to technical, safety, or economic reasons. The EPA believes that best management practices can be implemented to safely and effectively minimize the emissions associated with gas well liquids unloading. However, with respect to commenters who believe that a well affected facility/designated facility that conducts gas well liquids unloading should only include liquids unloading events that vent, we disagree. As one of the commenters noted, and we agree, unintended/unplanned venting could occur from a malfunction or error and the EPA would want owners and operators to be required to follow best management practices and other reporting and recordkeeping requirements. Owners or operators can and should develop best management plans to minimize venting during liquids unloading, to include both planned/designed venting events and those venting events that occur that are unplanned.

To conclude, the EPA has maintained its proposal that each well affected facility that unloads liquids is subject to the requirement to employ techniques or technology(ies) that minimize or eliminate venting of emissions during liquids unloading events to the maximum extent. For unloading technologies or techniques that result in venting to the atmosphere, the final rule requires that owners or operators employ best management practices that meet minimum specified criteria to minimize venting of methane and VOC emissions for each gas well liquids unloading operation. Unloading events that employ non-venting liquids unloading technologies and techniques that do not result in venting of methane and VOC emissions to the atmosphere are not subject to best management plan requirements and the associated recordkeeping and reporting requirements under the rule. An owner or operator of a well affected facility that employs non-venting liquids unloading technologies and techniques is only required to comply with minimal recordkeeping and reporting requirements. In instances where there may be an unplanned venting event, that event would be subject to the best management practices to minimize venting of emissions and the associated recordkeeping and reporting requirements. The EPA believes that the final work practice standard and associated recordkeeping and reporting requirements will incentivize owners or operators of well affected facilities and well designated facilities to minimize or eliminate the venting of emissions to the extent possible during liquids unloading events.

b. Recordkeeping and Reporting Requirements

In the December 2022 Supplemental Proposal, the EPA proposed specific recordkeeping and reporting requirements related to well liquids unloading operations. Wells that utilized a non-venting method would have been required to maintain records of the number of well liquids unloading operations that occur within the reporting period and the method(s) used for each well liquids unloading operation. A summary of this information would also have been required to be reported in the annual report. In recognition that under some circumstances, venting could occur when a selected liquids unloading method that is designed to not vent to the atmosphere is not properly applied ( e.g., a technology malfunction or operator error), under the proposed rule, owners and operators in this situation would have been required to record and report these instances, as well as document and report the length of venting and what actions were taken to minimize venting to the extent possible. Additionally, for wells that utilize methods that vent to the atmosphere, the proposed rule would have required: (1) Documentation explaining why it is infeasible to utilize a non-venting method due to technical, safety, or economic reasons; (2) development of best management practices that ensure that emissions during liquids unloading are minimized; (3) employment of the best management practices during each well liquids unloading operation and maintenance of records demonstrating that the best management practices were followed; and (4) reporting in the annual report both the number of well liquids unloading operations and any instances where the well liquids unloading operations did not follow the best management practices.

Comment: Several commenters requested that the EPA not require recordkeeping and reporting of non-venting liquids unloading events. One commenter suggested that operators conducting liquids unloading operations with zero methane and VOC emissions should not be subject to burdensome recordkeeping, reporting, and other requirements. One of the commenters noted that the non-vented liquids unloading reporting requirements are not feasible due to the nature of those events and because of the administrative burden associated with the reporting requirements with no net gain in emissions reductions. Similarly, one commenter requested that the EPA remove reporting requirements that do not provide valuable emissions-related information.

Another one of the commenters opposed the proposed recordkeeping and reporting obligations on owners or operators, on the grounds that they would be burdensome and yield no environmental benefit for well unloading activities that do not vent. For example, they noted, owners or operators of well affected facilities where gas well liquids unloading occurs must submit annual reports: (1) identifying the well affected facility; (2) disclosing the number of gas well liquid unloading operations that occurred there during the reporting period; (3) describing the unloading operation method used each time; and (4) reporting any deviations in detail along with corrective actions. See, e.g., proposed 40 CFR 60.5410b(b) and 60.5415b(b). The commenter stated that when unloading operations do not result in any vented emissions, these reports serve no purpose. To avoid this result, the commenter recommended that the EPA clarify that the standards for gas well liquids unloading operations apply only to those operations that result in emissions to the atmosphere. The commenter stated that this action would appropriately limit the recordkeeping and reporting obligations and would still allow the EPA to gather compliance information for a well that vents to the atmosphere during liquid unloading. The commenter added that the EPA should also make similar changes to proposed 40 CFR 60.5390c in EG OOOOc.

One commenter recommended that proposed recordkeeping and reporting for liquids unloading operations be simplified into a manageable framework for operators and streamlined for liquid unloading operations that vent to the atmosphere. The commenter noted that the information proposed by the EPA within 40 CFR 60.5420b and 40 CFR 60.5420c for the recordkeeping and reporting as it pertains to liquid unloading operations is focused more on an operator's tracking and certifying techniques and less on allowing an operator to perform the necessary procedures to unload liquids accumulated within the wellbore and maintain natural gas production with as minimal emissions as possible. To address this shortcoming, the commenter suggested that the EPA define the data that operators should track per unloading operation and remove all superfluous records that generate additional burden for the operator and the EPA without added environmental benefit. The commenter provided that these suggestions assume that liquid unloading operations are to be conducted using a work practice standard.

Furthermore, the commenter contended that the current proposed recordkeeping requirements do not offer a reasonable framework for operators to maintain compliance assurance. In fact, the commenter stated, the EPA has included a certification by a professional engineer for every instance a well unloading operation vents emissions to the atmosphere, in 40 CFR 60.5420b(c)(2)(ii)(B) and 40 CFR 60.5420b(b)(3)(ii)(B), based on the proposed zero-emissions standard. The commenter noted that an owner or operator may not know about gas well liquids unloading events that result in venting of emissions to the atmosphere until the liquid operation is taking place, based on a variety of parameters. For context, the commenter stated that a single well affected facility may undergo multiple liquid unloading operations in a single compliance period. For example, one well may necessitate an unloading schedule of four times in a year. Based on best management procedures, three of these events may occur with zero emissions, while one of the events might vent to atmosphere for a short duration using the same technique. The commenter believed the justification provisions in 40 CFR 60.5420b(c)(2)(ii)(B) to be untenable when the same technique used on a well may result in zero emissions during some liquid operations but not during all liquid unloading operations in the same compliance period. The commenter asserted that the fact is that in some instances a well liquid unloading operation may need to vent emissions for a short duration, sometimes as little as 30 minutes, to safely perform the liquid unloading operation. The commenter therefore requested that the EPA:

1. Remove the additional engineering certification statements under the guise of technical demonstrations. These additional certifications would be unnecessary if the standard followed a work practice procedure.

2. Limit recordkeeping and reporting to liquid unloading operations that result in emissions. This would reduce the administrative burden for thousands of liquid unloading operation events. This is also consistent with how both Colorado and New Mexico have organized recordkeeping and reporting for their state regulations.

Similarly, another commenter requested that the recordkeeping and reporting requirements be amended to be a workable framework for operators to assure compliance, including removal of the certification statement by an engineer in every instance that venting may occur.

Another commenter similarly argued that the EPA should not require recordkeeping or reporting for each well liquid unloading operation conducted during the year unless the EPA has defined “well liquid unloading operation” to mean only those well liquid unloading operations intended to vent to the atmosphere. As the EPA recognized in its supporting documentation, the commenter reports that one primary methodology that may be used to reduce or eliminate venting from removal of liquids of gas wells is a plunger lift. In most operational scenarios, a plunger lift will assist with liquid removal from the wellbore without any venting to the atmosphere. The plunger lift will operate either on a set cycle or based upon pressures reflected in the wellbore. However, not all plunger lifts are designed to have the necessary equipment onsite to track each cycle of the plunger lift. Thus, the commenter explains, the EPA's proposal could require installation of equipment to track the plunger cycles while providing no emissions reductions benefits. The commenter noted that the EPA has not fully evaluated the cost of installing and operating such tracking equipment in the BSER analysis, and given that there will be no emissions benefits, the EPA cannot show that such a requirement would be cost-effective. The commenter added that even where equipment is available to track the number of wellbore liquids removal events that do not vent to the atmosphere, the operational costs of undertaking that tracking are considerable and the data collected would be significant. According to the commenter, the EPA has provided no reasonable explanation for its need to obtain and track data relating to the number of wellbore liquids removal events that do not vent to the atmosphere. The commenter also stated that the EPA provides virtually no explanation for its decision to stick with option 1, other than the fact that “malfunctions” can result in vented emissions from liquids removal operations that would otherwise meet the zero-emissions standard. The commenter added that the EPA has no basis for concern with respect to malfunctions as it has implemented a robust AVO and OGI inspection program that would be expected to identify wells that have emissions during liquids removal that were not expected or intended.

The commenter concluded that one simple solution to this problem is to define well liquids unloading to mean only those wellbore liquids removal events that are intended to vent to atmosphere. By defining well liquids unloading in such a manner, the commenter believed, the EPA would encourage operators to find solutions that eliminate venting and to ensure that operators not only implement certain emissions reduction requirements to reduce venting to atmosphere but also record and report on those instances that do result in venting to the atmosphere.

One commenter cited from the EPA-referenced study by Dr. Allen, University of Texas, Environmental Science & Technology, December 9, 2014, Methane Emissions from Process Equipment at Natural Gas Production Sites in the United States: Liquids Unloadings, “Some wells with plunger lifts are automatically triggered and unload thousands of times per year.” The commenter stated that just a single well with thousands of unloading events per year would create a significant reporting burden, and when wells do not vent, they argued, this reporting should not be required.

Response: The EPA considered the commenters' concerns and examples provided regarding the burden associated with the proposed liquids unloading operations recordkeeping and reporting requirements. These concerns were evaluated along with the comments received on the zero-emissions standard. The EPA agrees that requiring an owner or operator to comply with some of the proposed recordkeeping and reporting requirements in instances where an unloading event does not result in venting to the atmosphere would impose a burden without any added benefit environmentally ( e.g., requiring that the number of liquids unloading events that occurred when implementing a non-venting liquids unloading technology or technique be tracked and reported).

As discussed under section X.F.3.a of this document, the EPA has determined that the intermittent and necessary nature of the variable methods and technologies employed to unload liquids, the inability to reliably measure emissions, and the unpredictable nature as to when it may be necessary to vent emissions makes a work practice standard more practical and appropriate for liquids unloading operations than a zero-emissions standard. As a result of this determination, the final rule requires owners or operators of an affected gas well facility that unloads liquids to employ techniques or technology(ies) that minimize or eliminate venting of emissions during gas well liquids unloading events to the maximum extent. For unloading events that result in venting to the atmosphere, the final rule requires owners or operators of well affected facilities/well designated facilities employ best management practices to minimize venting of methane and VOC emissions for each gas well liquids unloading operation, in addition to having to comply with the associated recordkeeping and reporting requirements. Where liquids unloading events were conducted using a technology/technique that eliminates venting to the atmosphere, the final rule only requires owners and operators to report the identification of the well along with the non-venting technology or technique used in their annual report. Where unplanned venting occurs from these wells during a compliance period, an owner or operator would be required to follow their best management practices plan for such events and comply with the associated recordkeeping and reporting requirements for those events.

As a work practice standard, the engineering certification statement that would be required under the December 2022 Supplemental Proposal, which would have required an explanation of why it is infeasible to utilize a non-venting method due to technical, safety, or economic reasons, is unnecessary and has been removed from the final rule. Additionally, because there is no longer a requirement to comply with a zero-emissions standard, there is no longer a need to maintain records or reports containing information on a change of compliance method from a zero-emissions standard to the implementation of best management practices and vice versa.

4. Well Completions

In the November 2021 Proposal, the EPA proposed to retain the requirements found in NSPS OOOO and NSPS OOOOa for reducing methane and VOC emissions through REC and completion combustion. The BSER analysis is unchanged from what was presented in the November 2021 Proposal (see 86 FR 63234–36, section XII.I: Proposed Standards for Well Completions). The proposed regulatory text included in the December 2022 Supplemental Proposal was similar to the regulatory text found in 40 CFR 60.5375a for NSPS OOOOa. While the regulatory text was similar, the EPA was made aware of potential confusion related to the well completion requirements and well completion recordkeeping requirements for wildcat wells, delineation wells, and low-pressure wells. Therefore, the proposed regulatory text for NSPS OOOOb included language to clarify these particular standards for new, modified, and reconstructed sources moving forward. First, the EPA proposed regulatory text at 40 CFR 60.5375b(f) to clearly state the requirement to route emissions from wildcat well, delineation well, and low-pressure well completions to a completion combustion device in any instance (unless combustion creates a fire or safety hazard or can damage tundra, permafrost, or waterways). The EPA was also made aware from implementation of NSPS OOOOa that owners and operators were unclear as to whether they can choose to comply with 40 CFR 60.5375a(f)(3)(ii) and make a claim of technical infeasibility for the separator to function, which then precludes the requirement to route recovered emissions to a completion combustion device. The EPA noted in the December 2022 Supplemental Proposal that this preclusion was not the EPA's intent in NSPS OOOOa and for this reason, we proposed to clearly specify at 40 CFR 60.5375b(f) that an alternative to routing to a separator (instead of routing all flowback to a completion combustion device) is available only when the owner or operator is able to operate a separator and has the separator onsite (or otherwise available for use) and ready for use to comply with the alternative during the entirety of the flowback period. Second, the EPA proposed to eliminate recordkeeping requirements which are not necessary for wildcat wells, delineation wells, and low-pressure wells that had previously been included in NSPS OOOOa. Specifically, the EPA proposed to not require records for “beneficial” use of recovered gas ( i.e., routed to the gas flow line or collection system, reinjected into the well or another well, used as an onsite fuel source, or used for another useful purpose that a purchased fuel or raw material would serve) nor records of “specific reasons for venting in lieu of capture.” These records were not required for wildcat wells, delineation wells, and low-pressure wells because the well completion standards at 40 CFR 60.5375b(f) require that all flowback, or gas recovered from flowback through the operation of a separator, be routed to a completion combustion device ( i.e., there will not be an instance, when complying with 40 CFR 60.5375b(f), that beneficial use of recovered gas will occur).

The EPA did not receive comments on the EPA's well completion proposed requirements that would lead the EPA to change what was proposed in the December 2022 Supplemental Proposal and the EPA has finalized the well completion requirements as proposed for both the NSPS OOOOb and EG OOOOc.

G. Centrifugal Compressors

In section X.G of this document, the final NSPS OOOOb and EG OOOOc requirements for centrifugal compressors are summarized. The BSER analysis for wet seal centrifugal compressors is unchanged from what was presented in the December 2022 Supplemental Proposal (see 87 FR 74784–85, section IV.G: Centrifugal Compressors). However, detailed comments were received on the December 2022 Supplemental Proposal on the following topics: (1) redefining the affected facility to include compressors with dry seals and the proposed standard, (2) the EPA's proposal to base the standard of performance as a numeric standard for self-contained wet seal compressors and centrifugal compressors equipped with dry seals, (3) the need to clarify that the standard is on a per-seal basis, (4) other inherently low-emitting compressor configurations, (5) the EPA's extension of requirements to centrifugal compressors located at centralized production facilities, and (6) wet seal compressors equipped with a seal oil gas separation system utilized on the Alaska North Slope (ANS). For each of these topics, a summary of the proposed rule (where relevant), the comments, the EPA responses, and changes made in the final rule (if applicable), are discussed here. These comments and the EPA's responses to these comments generally apply to the standards proposed in both the NSPS OOOOb and EG OOOOc. The instances where the comment and/or response only applies to the NSPS OOOOb or EG OOOOc are noted. The EPA's full response to comments on the November 2021 Proposal and December 2022 Supplemental Proposal, including any comments not discussed in this preamble, can be found in the EPA's RTC document for the final rule.

1. Redefining the Affected Facility To Include Centrifugal Compressors With Dry Seals and the Proposed Standard

In the December 2022 Supplemental Proposal, the EPA redefined the affected facility to include compressors with dry seals and proposed a dry seal volumetric flow rate of 3 scfm (per seal) as a numeric emissions standard.

Comment: Several commenters stated that the EPA should not adopt the proposed dry seal standard of 3 scfm (per seal) because that standard is unsupported and not adequately justified. Specifically, two commenters stated that the EPA must first obtain data—both on cost and, more importantly, on feasibility and reasonableness of the standard itself—to support a proper BSER analysis. Any other approach, according to the commenters, would be arbitrary and capricious. The commenters described three main concerns (with support for each of their concerns detailed in the RTC document for this action) with the BSER determination. These concerns included the following:

(1) The commenters stated that the BSER determination contains insufficient data to support the proposed standard or the cost that would be required to maintain it. The commenters specifically dispute the appropriateness of reliance on section 95668(d)(4–9), California's Regulations for Greenhouse Gas Emission Standards for Crude Oil and Natural Gas Facilities, to support the standard. Research into the underlying sources of the California Air Resources Board (CARB) regulation does not yield supporting information for the development of the 3 scfm standard. According to the commenters, there is no data in the California rulemaking supporting any numeric standard for dry seals, much less a specific rate of 3 scfm.

(2) The commenters stated that the BSER determination does not consider data showing that seal emissions rate is a function of compressor size and suction pressure, and consequently, the standard does not properly account for compressor size; and

(3) The commenters stated that record is devoid of any information (or data) indicating that proper maintenance and repair could reduce such compressors' dry seal emissions rate to 3 scfm or less, or any information regarding the associated costs of doing so.

Several commenters emphasized that more reliable information and data are or will be available that could be used in developing a dry seal emissions standard. One of the commenters stated that based on data submitted to the EPA pursuant to GHGRP subpart W for the 2021 calendar year, dry seal compressor driver power output ranged between 5 and 42,000 horsepower and for wet seals the compressor driver power output ranged between 40 and 53,665 horsepower. The commenter expressed that it does not believe compressors associated with the higher end of this range should be expected to operate the same as compressors closer to the lower end of this range.

Several commenters stated that, for transmission and storage, the majority of turbines are manufactured by Solar Turbines. The commenters suggested that the Solar Turbine Product Information Letter (PIL) be considered as a superior reference compared to the Natural Gas STAR document. Information available from Solar shows that dry seal emissions rates are a function of compressor type ( e.g., size) and operating (suction) pressure. The commenters reported that the PIL provides data plots for a range of compressor sizes and suction pressures. The commenters stated that the PIL data plots clearly indicate that 3 scfm will be exceeded during standard operations for many units and/or at many suction pressures that are common on transmission systems. Since that data shows higher emissions rates for many applications, the commenters contended that it alone refutes the basis of the EPA's proposed 3 scfm emissions rate. According to the commenters, if the EPA insists on proceeding with a standard for dry seal compressors at this time, the EPA should establish a standard based on function/operating conditions for the seal ( i.e., unit size and suction pressure); or, if the standard is a single emissions rate, it must be high enough to address the largest units and highest suction pressures in natural gas operations.

As a result of these concerns, some commenters provided recommendations to the EPA for development of a dry seal emissions standard:

• One commenter stated that the EPA should supplement the docket with information to support why the proposed value is representative of the population of dry seal compressors across the nation (taking into consideration compressor size variability).

• Several commenters recommended that the EPA postpone establishing any type of quantitative threshold for dry seal centrifugal compressors until after it finalizes amendments to GHGRP subpart W. See 87 FR 36920 (June 21, 2022) (proposed rule). Once those amendments are implemented, the commenters contended, the EPA would have thousands of data points to give a more accurate dry seal centrifugal compressor measurements that can be used for a subsequent emissions threshold.

• Several commenters stated that if the EPA decides to re-propose a numeric emissions standard for dry seal compressors, it must first identify reliable information about emissions rates that are achieved by well-maintained dry seal compressors and the maintenance/replacement activity needed to achieve them. Because of the functional dependence on unit size and suction pressure, they contended, it is likely that a single emissions rate is not sufficient, unless that rate is high enough to address the largest units and highest suction pressures in natural gas operations. Second, they suggested that any emissions rate standard must be expressed as a per-seal standard. Finally, they stated that, if the standard would require yearly measurements and monitoring of these compressors for the first time, as the current proposal does, the cost of monitoring would be part of the proposed standard and should be accounted for in the BSER analysis.

One commenter noted that, in principle, they do not object to a standard for dry seal compressors. However, they suggested that the EPA should: (1) recognize that 3 scfm is an approximate average rate for some dry seal compressors, but it is not characteristic of units that may have an emissions rate several times higher— e.g., large compressors with relatively high suction pressure; (2) consider the upper end range or tiered emissions rates in the standard; (3) conduct analysis and consider cost effectiveness of installing a seal vent recovery/control system if the emissions rate cannot be met; (4) account for the cost of additional monitoring that a numeric standard would require; (5) clarify that the selected standard applies for each dry seal, not for the entire compressor; and (6) if a standard is retained (considering the factors above), propose a work practice standard and define the schedule for operators to resolve the issue when a unit exceeds its defined emissions rate threshold.

While several of the commenters specifically recommended that the EPA wait for more accurate data based on GHGRP subpart W, they added that, if the EPA is intent on establishing a dry seal emissions threshold before receiving the GHGRP subpart W reports, they recommended relying upon the manufacturer's specified maximum leak rate for a particular unit. The commenters noted that a recent review of dry seal leak curves from a major supplier of centrifugal compressors to the natural gas industry indicates that dry seal leakage rates can vary from 2 to 20 scfm per compressor (with two seals per compressor), depending on the make, model, and operating suction pressure of the compressor. If the EPA wishes to set one threshold applicable to all dry seal centrifugal compressors in this rulemaking, the commenters recommended that the EPA set the threshold at 10 scfm per primary dry seal to allow for sufficient variability among existing dry seal leak rates.

Response: The EPA has evaluated these comments and acknowledges that the data available on dry seal compressor emissions and flow rates was limited and that a 3 scfm volumetric flow rate performance standard may not be achievable for some centrifugal compressors equipped with dry seals, even when properly maintained and the dry seal is not in need of repair. Prior to receipt of these comments and based on available information and data, it was believed that these higher-emitting dry seal compressors represented compressors in need of repair or maintenance. In fact, the EPA had not previously regulated centrifugal compressors equipped with dry seals because they were considered low-emitting when compared with compressors equipped with wet seals. What has become evident, however, is that some centrifugal compressors equipped with dry seals emit more than previously believed and that a properly functioning compressor equipped with a dry seal can be higher-emitting than a centrifugal compressor equipped with a wet seal that is subject to requirements under NSPS OOOOb.

Given that compressors equipped with wet seals are regulated under NSPS OOOO, NSPS OOOOa, and the final NSPS OOOOb, and given that compressors equipped with dry seals are known to emit more than some compressors with wet seals, the final rule retains the requirement to conduct volumetric flow rate monitoring and associated maintenance and repair (as needed) of these compressors consistent with what is required for centrifugal compressors equipped with wet seals. However, the EPA has revised the proposed volumetric flow rate performance standard for centrifugal compressors with dry seals to be 10 scfm/seal ( i.e., representing a maximum flow rate applicable to all dry seals). Based on manufacturer data provided on dry seal rate curves for differing compressor models and configurations, a 10 scfm per seal flow rate performance standard is supported as a maximum flow rate performance standard that could be applicable to all dry seals until additional flow rate and emissions data are obtained under GHGRP subpart W.

The 10 scfm per seal flow rate performance limit reflects ordinary performance of a well-maintained unit, therefore minimal additional costs are expected. In many instances, compressors equipped with dry seals will already be required to conduct annual compressor vent volumetric flow rate monitoring under GHGRP subpart W. Owners or operators of these compressors will be subject to minor recordkeeping and reporting requirements, and maintenance and repair requirements would only apply where the volumetric flow rate performance standard of 10 scfm per seal is exceeded. For owners or operators not already required to conduct annual compressor vent volumetric flow rate monitoring under GHGRP subpart W, the only additional cost is the cost of conducting the required volumetric flow rate monitoring. See discussion in section XI.G.2 of this document on the EPA's decision to establish centrifugal compressor flow rate performance standards as work practice standards and not as numeric limits where an exceedance would be considered a violation.

As commenters noted, the EPA has requested flow rate/emissions information under GHGRP subpart W for compressors equipped with dry seals. Based on information received, the EPA may revisit and revise the 10 scfm per seal volumetric flow rate performance standard for compressors equipped with dry seals in the future.

2. Numeric Standard Versus Work Practice Standard

In reviewing the BSER determination and standards for centrifugal compressors proposed in November 2021, the EPA stated that it is feasible to prescribe a standard of performance, rather than a work practice standard, for centrifugal compressors complying with the NSPS OOOOb self-contained wet seal centrifugal compressor and EG OOOOc wet seal compressor volumetric flow rate performance standards. The BSER was therefore proposed to conduct repair and maintenance activities to maintain emissions at or below a specified flow rate. Based on this rationale, the EPA proposed a numeric emissions limit requirement. The major difference between the numeric emissions limit standard proposed under the December 2022 Supplemental Proposal and what the EPA proposed in November 2021 was that under the December 2022 Supplemental Proposal, owners and operators would be required to maintain emissions at or below the specified emissions limit (a measured emissions flow rate) whereas under the November 2021 Proposal, owners or operators would have been required to conduct repairs and maintenance after discovering an exceedance of a flow rate of the specified numeric emissions limit (a measured emissions flow rate).

Comment: Several commenters asserted that the rule should clarify the required compliance obligations, include a repair or replacement timeline, and eliminate avoidable emissions from repair to wet and dry seals. According to the commenters, the proposed NSPS rule was drafted to require an emissions flow rate limit for wet and dry seals. If the individual seal exceeds the 3 scfm (or a group of seals exceeds the applicable standard), the EPA expects the operator to repair or replace that seal, as appropriate. The proposed rule did not describe what is required if the measurement at the seal vent exceeds the applicable flow rate. The commenters recommend that dry seal centrifugal compressors and self-contained wet seal compressors be regulated through work practice standards. The commenters also recommend that the rule provide a proposed timeline for repair or replacements, as well as delay-of-repair provisions, consistent with nearly all other NSPS drafted by the EPA.

According to one commenter, the EPA, without sufficient explanation, summarily turned California's work practice standard into an emissions rate limitation. The commenter alleged there is nothing in the record about what measures would need to be implemented, and the associated cost, to meet such a limitation. The commenter stated that a delay-of-repair provision in such a regulatory scheme appropriately recognizes that the unit must be shut down to effect any such repair and replacement and that parts availability and supply chain disruptions may be relevant to how quickly the repair or replacement can be made. In addition, the commenter stated there is no record information indicating that it is feasible for the source to anticipate that a well-functioning wet seal that meets the 3 scfm limitation for 1 year will exceed it before the next year's test, or the cost of doing so (if possible).

Several commenters suggested that the EPA allow one of the following corrective actions by an operator within 2 years if the applicable flow rate performance standard is exceeded:

(1) repair or replace the dry seal, wet seal, or internal seal gas recovery system; and

(2) route emissions from the dry seal vent through a closed vent system or from the degassing vent using a cover and closed vent system a control device; or

(3) route emissions from the primary dry seal vent through a closed vent system or route the degassing vent using a cover and closed vent system to a process.

The commenters recommended that if an operator cannot complete the corrective action within 2 years, then a corrective action plan with work scope and alternate schedule be submitted to the EPA under a work-practice-based framework. According to the commenters, 2 years is a reasonable corrective action period since the corrective actions listed can require significant planning, scheduling, engineering, and construction. They explain that exceedance of the flow rate performance standard after 2 years (in the absence of a corrective action plan), or after the time stated in the corrective action plan, would result in a deviation subject to recordkeeping and reporting requirements similar to other types of compressors.

Some commenters stated that the delay-of-repair provision is consistent with delay-of-repair requirements under 40 CFR 60.5397a(h)(3), requiring repair within 2 years, or the next scheduled shutdown (whichever is earlier), where repairs are technically infeasible, where repairs would require a vent blowdown, a compressor station shutdown, a well shutdown, or well shut-in, or where it would be unsafe to repair. Further, the commenters added that the EPA has taken this approach before in most of its NSPS regulations. In fact, the EPA has also proposed a delay-of-repair approach in other contexts of the December 2022 Supplemental Proposal for the NSPS where emissions caused by the repair would exceed the existing leak rate.

One commenter suggested 90 days as a reasonable timeframe given the significant variety of repair methods (including replacement) that may be appropriate for these units, as the EPA recognizes in its preamble.

Several commenters proposed revisions to regulatory language to implement the requested work practice approach and delay-of-repair provision.

Response: The EPA acknowledges that the record for the 3 scfm per seal volumetric flow rate performance standard supports a work practice standard and not a numeric standard for centrifugal compressors equipped with wet seals. This is because the application of a measurement methodology to centrifugal compressors is not always practicable due to technological or economic limitations. It is not practicable here for an exceedance of the 3 scfm per seal volumetric flow rate to be a violation when the annual performance-based flow rate reflects whether there are performance issues with a seal that need to be addressed in order to take action to minimize the emissions/leak. This is similar to the basis and monitoring established for fugitive emissions component requirements, where a leak based on periodic monitoring triggers requirements to minimize the emissions/leak.

The final rule has therefore been revised so that the format of the 3 scfm per-seal performance-based volumetric flow rate performance standard for compressors equipped with wet seals is implemented as a work practice standard and not as a numeric limit where an exceedance would be considered a violation. Specifically, the final rule for reducing GHGs and VOC from new centrifugal compressors is repair or replacement of the wet seal where, based on the required monitoring, the per-seal volumetric flow rate performance standard is exceeded. If the volumetric flow rate measurement of the centrifugal compressor is greater than 3 scfm (in operating or standby pressurized mode) or a combined compressor seal rate greater than the number of compressor seals multiplied by 3 scfm, an owner or operator must repair or replace the centrifugal compressor seal within 30 calendar days after the date of the volumetric emissions measurement. As such, for centrifugal compressors equipped with wet seals, the volumetric flow rate of 3 scfm is an action level that, if exceeded, triggers the action of repairing or replacing the seal and is not a numeric limit.

Delay-of-repair provisions under a work practice standard appropriately recognize that the unit must be shut down to affect any such repair and replacement and that parts availability and supply chain disruptions may be relevant to how quickly the repair or replacement can be made. As such, the final rule allows for a delay of repair if the repair or replacement would require a vent blowdown, or it would otherwise be infeasible or unsafe, until the next process unit shutdown. Specifically, delay of repair would be allowed if the repair or replacement of a seal (1) is technically infeasible, (2) would require a vent blowdown, (3) would require a process unit or facility to shut down, (4) needs to be delayed because parts or materials are unavailable, or (5) would be unsafe to repair during operation of the unit. In cases where there is a need for a delay of repair, the repair must be completed during the next scheduled process unit or facility shutdown for maintenance, after a scheduled vent blowdown, or within 2 years, whichever is earliest.

Delay-of-repair provisions under a work practice standard appropriately recognize that the unit must be shut down to effect any such repair and replacement and that parts availability and supply chain disruptions may be relevant to how quickly the repair or replacement can be made. As such, the final rule allows for a delay of repair if the repair or replacement would require a vent blowdown, or it would otherwise be infeasible or unsafe, until the next process unit shutdown. Specifically, delay of repair would be allowed if the repair or replacement of a seal (1) is technically infeasible, (2) would require a vent blowdown, (3) would require a process unit or facility to shut down, (4) needs to be delayed because parts or materials are unavailable, or (5) would be unsafe to repair during operation of the unit. In cases where there is a need for a delay of repair, the repair must be completed during the next scheduled process unit or facility shutdown for maintenance, after a scheduled vent blowdown, or within 2 years, whichever is earliest. Delay of repair beyond the next scheduled compressor shutdown for maintenance is allowed for a centrifugal compressor wet and dry seal, if seal replacement is necessary during the compressor shutdown for maintenance, seal supplies have been depleted, and seal supplies had been sufficiently stocked before the supplies were depleted. Delay of repair beyond the next compressor shutdown for maintenance will not be allowed unless the next compressor shutdown for maintenance occurs sooner than 6 months after the first compressor shutdown for maintenance.

The format of the volumetric flow rate performance standard for centrifugal compressors equipped with dry seals has also been revised in the final rule as a work practice standard and not as a numeric limit. However, for centrifugal compressors equipped with dry seals, the volumetric flow rate performance standard is 10 scfm per seal and not 3 scfm per seal (see section XI.G.1 of this document for discussion on centrifugal compressors with dry seals). As such, for centrifugal compressors equipped with dry seals, the volumetric flow rate of 10 scfm is an action level that, if exceeded, triggers the action of repairing or replacing the seal and is not a numeric limit.

3. Clarification That the Standard Is Based on a Per-Seal Basis

Comment: Several commenters requested clarification that the volumetric standard applies to each seal and not each compressor and that the rule text clearly address manifolded vents on a combined basis to reflect this. The commenters cited the precedent set by the CARB where wet seal compressors in California are restricted to 3 scfm per seal, and not per compressor as set forth in 17 Code of Colorado Regulations (CCR) section 95668.

One of the commenters noted that the EPA's preamble discussion, and at least some of the proposed rule text, imply that the emissions rate would be on a per-seal basis, and the commenter understands this to be the EPA's intent. The commenter asserted that it is important that the EPA's final rule more clearly reflect this intent. Specifically, according to the commenter, the proposed text provided in 40 CFR 60.5380b or 40 CFR 60.5385b(a) (and parallel EG OOOOc language) does not provide the distinction that the limits are per seal. The commenter asserted that it would be impractical for a compressor with multiple seals (centrifugal) to operate in the same way as a compressor with only a single seal.

The commenter stated that the rule language must more clearly address manifolded vents on a combined basis. The commenter noted that the December 2022 Supplemental Proposal preamble provided that the manifolded wet and dry seal flow rate must be “less than or equal to the number of compressors multiplied by 3 scfm (in operating or standby pressurized mode).” The commenter supported this approach, as it reflects the practicalities of measuring emissions from manifolded seals. The commenters also note that the approach is supported by the 2006 Natural Gas STAR report, which states that emissions rates from two seal systems would be double the emissions from a single seal system.

The commenters elaborated on why they believed that this was the EPA's intent (for the standard to be based on a per-seal basis) and several commenters provided in-line regulatory text changes where they believed the clarification was needed.

Response: The EPA agrees that the basis and intent of the standard is that it be applied on a per-seal basis and that clarity was needed in the NSPS OOOOb and EG OOOOc regulatory text. The final rule regulatory text has been revised to make this clear as suggested by the commenters. Specifically, clarifying changes have been made to 40 CFR 60.5380b, paragraphs (a)(5) through (7) of NSPS OOOOb, and 40 CFR 60.5392c, paragraphs (a)(1) and (2), of EG OOOOc.

4. Other Inherently Low-Emitting Compressor With Wet Seal Configurations

Comment: In their comments on the November 2021 Proposal, one commenter stated that one type of low-emissions wet seal utilized in compressors in the transmission and storage sector is a mechanical seal, in which metal (tungsten carbide) is seated against carbide, with oil pressing against the outside of the actual seal. Because the oil is not in contact with the natural gas, the commenter explains that these wet seals have generally zero degassing emissions. According to the commenter, it makes no sense to subject such a zero-emissions wet seal to control requirements. Accordingly, the EPA should exclude compressors utilizing mechanical wet seals from the requirements otherwise applicable to wet seal compressors.

The commenter provided additional information on mechanical seals in their comments on the December 2022 Supplemental Proposal for the EPA to evaluate that provided support that, with respect to mechanical wet seals, when a differential pressure is maintained on the system, there is no off-gassing of the lube oil. The commenter attached an example to their comment letter that shows that the oil is pumped via the seal oil pump to the seal gas bottle, when the seal oil pressure is maintained at 32 psi above discharge gas pressure.

Response: The EPA has evaluated the information provided by the commenter on mechanical seals for both the November 2021 Proposal and the December 2022 Supplemental Proposal. The EPA has made the determination that mechanical wet seals are inherently low-emitting where (1) a differential pressure is maintained on the system, (2) there is no offgassing of the lube oil, and (3) the mechanical seal is integrated into the compressor housing. As such, the final rule definition of self-contained wet seal compressor has been revised, for purposes of regulation, to include mechanical wet seals where (1) a differential pressure is maintained on the system, (2) there is no off-gassing of the lube oil, and (3) the mechanical seal is integrated into the compressor housing. Self-contained wet seal centrifugal compressors are allowed to meet a 3 scfm/seal volumetric flow rate limit in lieu of being required to route emissions via a CVS to a control device or process under NSPS OOOOb.

5. Applicability of Requirements to Compressors Located at Centralized Production Facilities

The EPA proposed in the November 2021 Proposal to define centralized production facilities separately from well sites because the numbers and sizes of equipment, particularly reciprocating and centrifugal compressors, are larger than for standalone well sites, which would not be included in the proposed definition of “centralized production facilities.” In the 2016 NSPS OOOOa, the EPA exempted reciprocating and centrifugal compressors located at well sites from the applicable compressor standards. However, the EPA believed the definition of “well site” in NSPS OOOOa may have caused confusion regarding whether centrifugal compressors located at centralized production facilities were also exempt from the standards, which was not our intent.

To clarify our intent, the EPA defined centralized production facility as follows in the December 2022 Supplemental Proposal in both the NSPS OOOOb and EG OOOOc:

Centralized production facility means one or more storage vessels and all equipment at a single surface site used to gather, for the purpose of sale or processing to sell, crude oil, condensate, produced water, or intermediate hydrocarbon liquid from one or more offsite natural gas or oil production wells. This equipment includes, but is not limited to, equipment used for storage, separation, treating, dehydration, artificial lift, combustion, compression, pumping, metering, monitoring, and flowline. Process vessels and process tanks are not considered storage vessels or storage tanks. A centralized production facility is located upstream of the natural gas processing plant or the crude oil pipeline breakout station and is a part of producing operations.

Additionally, the EPA defined the affected facility under the NSPS OOOOb (and designated facility under EG OOOOc) as:

(b) Each centrifugal compressor affected facility [and designated facility under the EG OOOOc], which is a single centrifugal compressor. A centrifugal compressor located at a well site is not an affected facility under this subpart. A centrifugal compressor located at a centralized production facility is an affected facility under this subpart.

For purposes of analyses, the EPA determined it was appropriate to apply the same emission factors to centrifugal compressors located at centralized production facilities as those used for centrifugal compressors at gathering and boosting compressor stations. Given the results of that analysis, the EPA proposed to apply the proposed NSPS OOOOb requirements to centrifugal compressors located at centralized production facilities. At that time, the EPA proposed a new definition for “centralized production facility” intended to distinguish compressors at standalone well sites where the EPA has determined that the standard should not apply.

Comment: One commenter requested that the EPA clarify the applicability of compressor standards to well sites. The commenter stated that the definition proposed for central[ized] production facilities may extend applicability to compressors located at well sites, which have historically been exempt from the compressor standards. As the EPA stated they have not updated their cost analyses with new information with respect to well sites, the commenters believe that extending applicability to well sites was not the EPA's intent. Another commenter urged the EPA to keep the current compressor exemptions shown in both subparts NSPS OOOO and OOOOa. The commenter specifically requests that the EPA maintain that each compressor “located at a well site, or an adjacent well site and servicing more than one well site, is not an affected facility.”

Response: The EPA has finalized the proposed requirements related to the definitions of the centrifugal compressor affected facility/designated facility and centralized production facility. Some of the commenters suggested that, by extending requirements to centralized production facilities, the EPA was extending requirements to well sites where centrifugal compressors were not previously regulated. That interpretation confirms that clarity was needed. Based on the proposed definition of the centrifugal compressor affected facility/designated facility, in addition to the proposed definition for centralized production facility as proposed in the December 2022 Supplemental Proposal, we believe that we clarified our intent. That intent is that centrifugal compressors located at well sites are not subject to requirements. However, centrifugal compressors located at centralized production facilities that consist of equipment at a single surface site used to gather, for the purpose of sale or processing to sell, crude oil, condensate, produced water, or intermediate hydrocarbon liquid from one or more offsite natural gas or oil production wells (including centrifugal compressors) are subject to centrifugal compressor requirements.

6. Wet Seal Compressors Equipped With a Seal Oil Gas Separation System Utilized on the Alaska North Slope (ANS)

Comment: One commenter representing Alaska oil and natural gas companies requested that the EPA revise the proposed EG for existing wet seal centrifugal compressors to address the characteristics of the wet seal compressors deployed in Alaska oil production operations. The commenter reported that their members use wet seal compressors at their Alaska North Slope (ANS) and Cook Inlet production fields to increase the pressure of residual gas captured in production operations to enable delivery to gas processing plants and/or reinjection into well fields. They noted that there are about 40 compressor trains on the ANS installed for this purpose. The compressors in use on the ANS were installed in the late 1970s through mid-1980s and have not been modified or reconstructed. They range in size from 15,140 hp to 53,665 hp. None are currently subject to NSPS OOOO or NSPS OOOOa.

The commenter stated that all the wet seal centrifugal compressors in Alaska are equipped with a seal oil gas separation system that separates gas from the sour seal oil exiting the compressor seal assembly, upstream from the degassing drum. On the ANS the gas captured in the seal oil trap is routed to various outlets for use as turbine fuel, low-pressure fuel gas, compressor suction, flare purge or to flare (for destruction). In Cook Inlet the gas is processed for delivery to market. The commenter noted that the EPA described this technology enthusiastically in the 2014 Natural Gas STAR Report. Sour seal oil passes through a “seal oil trap,” a type of separator, prior to routing to the seal oil degassing drum. The commenter described the seal oil traps in their comments on the November 2021 Proposal, which they resubmitted on the December 2022 Supplemental Proposal. The commenter included a process flow diagram of the seal oil recovery system on an ANS wet seal compressor. The commenter added that the EPA's 2014 Natural Gas STAR Report praised the seal gas recovery system deployed on the ANS as “highly effective at capturing degassing emissions from wet seal centrifugal compressors . . .”

While the commenter supported the concept of adopting a volumetric limit based on diligent maintenance and repair as BSER for control of emissions from wet seal compressor vents, they asserted that the record does not support that the proposed 3 scfm limit can be met for all wet seal compressors. The commenter expressed support for the concept of adopting a flow rate limit based on maintenance and repair as BSER for control of emissions from wet seal compressor vents because they believe that such an option avoids the safety risks, engineering challenges, and extravagant cost of capturing and flaring low-volume, low-pressure vent streams. They asserted that the problem with the EG OOOOc proposal is that the 3 scfm proposed limit does not account for variability in the size and configuration of wet seal compressors within the source category and is not demonstrated or achievable for wet seal compressors of the size and configuration of those deployed in oil and gas production operations in Alaska.

The commenter stated that they would support the designation of seal oil traps as an EG OOOOc compliance option for Alaska wet seal compressors. For several reasons, however, Alaska wet seal compressors equipped with seal oil traps do not uniformly meet the proposed 3 scfm limit. They explained that the volume of seal oil slip from a wet seal compressor correlates with compressor shaft size, pressure, and speed. Alaska wet seal compressors span a broad range of capacities, and the degassing drums serving the larger units vent higher volumes of seal gas. Attachment C to their comments provides a table showing flow rate data from 27 wet seal compressor degassing vents sampled by AOGA member Hilcorp for the EPA GHG emissions reporting. The table shows the flow rate per seal, but a single degassing drum can discharge gas from up to four seal oil traps. The variability in the data reflects the variability in size and configuration of the compressors and the fact that each seal oil trap operates on a discharge cycle, and a degassing drum may receive sour seal oil from up to four different seal oil traps at any moment. Depending on when in the cycle the sample is taken, the per-seal flow rate can exceed 3 scfm.

Based on the degassing drum flow rate data summarized in table 1 (of attachment C to their comment letter), the commenter proposed a volumetric flow limit for Alaska wet seal compressor vents of 9 scfm of methane and VOCs per seal, multiplied by the number of compressor seals venting through a common stack. For example, they note that a two-stage compressor has four seals (two per stage), all of which are manifolded into one vent to the atmosphere. If the per-seal flow limit was 9 scfm, the flow limit for the common vent should be 36 scfm.

Response: The EPA reviewed information materials submitted by commenters related to the wet seal centrifugal compressors in Alaska equipped with a seal oil gas separation system that separates gas from the sour seal oil exiting the compressor seal assembly, upstream from the degassing tank. These compressors are considered inherently low-emitting based on Natural Gas STAR and emissions/process information provided by the commenter. These wet seal compressors with the sour seal oil traps recapture gas and route the gas to the flare (simple pit flares), not to the “compressor suction [as with defined self-contained wet seal compressors].” These systems cannot always meet a 3 scfm limit due to the intermittent process affecting flow.

The final EG OOOOc rule provides a new definition for a “centrifugal compressor equipped with sour seal oil separator and capture system” and requires that, in Alaska, such compressors be allowed to meet a performance-based volumetric flow rate standard of 9 scfm/seal, in lieu of the 3 scfm/seal performance-based volumetric flow rate standard to account for the variability in the flow rate data provided by the commenter that reflects the variability in size and configuration of these compressors and the fact that each seal oil trap operates on a discharge cycle, and a degassing drum may receive sour seal oil from up to four different seal oil traps at any moment.

The final rule definition reads as follows:

Centrifugal compressor equipped with sour seal oil separator and capture system means a wet seal centrifugal compressor system which has an intermediate closed process that degasses most of the gas entrained in the sour seal oil and sends that gas to either another process or combustion device. The de-gas emissions are routed back to a process or combustion device directly from the intermediate closed degassing process; after the intermediate closed process the oil is ultimately recycled for recirculation in the seals to the lube oil tank where any small amount of residual gas is released through a vent.

Comment: In addition to the commenter's concerns related to the proposed volumetric performance-based standard requirement, the commenter added that the NSPS OOOOb capture and control requirements for new wet seal compressors are also not reasonably achievable for existing compressors in Alaska. The commenter noted that the December 2022 Supplemental Proposal's proposed EG OOOOc offers the NSPS OOOOb control options as a fallback for wet seal compressors that cannot meet the presumptive 3 scfm flow limit, but they stated that these options would require a cover on the degassing drums, connected through a closed vent system to process or to a control device that achieves a 95.0 percent reduction in emissions, should an existing compressor ever be modified or reconstructed. The commenter stated that in Alaska oil and gas production operations there is no cost-effective option to recover degassing drum emissions. Degassing drums vent small volumes of methane and VOCs at atmospheric pressure. They referred to flow rates reported in attachment C of their comment letter. They explained that the volumes reported are small because the seal oil traps capture and recycle most of the seal gas upstream of the degassing drum. They reported that operators would need to install new compression devices to boost degassing drum vent gas pressure to the approximately 20 psi that would enable delivery of those streams to the flare header line. The commenter stated that larger new compression devices would be required to boost vent gas to a much higher pressure that would enable delivery to a process line for injection into subsurface reservoirs.

According to the commenter, the combination of low methane and VOC recoveries with high capture costs makes the capture and control alternative very expensive on a cost-per-ton basis. They referred to Kinder Morgan's comments on the November 2021 Proposal, where Kinder Morgan provides that the 95.0 percent reduction requirement is technically infeasible and cost-prohibitive even for wet seal compressors located on natural gas pipelines in the lower 48 states. For wet seal compressors deployed in Alaska production operations with seal oil traps, the cost per ton of covering the degassing drum vents and reducing emissions from those vents by 95.0 percent would be prohibitive.

Response: As discussed earlier in this document, the EPA agrees that ANS compressors equipped with a sour seal oil separator and capture system are inherently low-emitting and that the costs of requiring routing to a control device or process would be cost-prohibitive for these compressors due to technical and costly retrofits that would be needed ( e.g., would need to install new compression devices to boost degassing drum vent gas pressure) if any of their existing ANS compressors were to be modified or reconstructed. The commenters provided information and data to support their request that these sources be allowed to meet a performance-based volumetric flow rate standard in lieu of having to route emissions to a control device or process. As provided by the commenter, and the EPA agrees, recovering degassing drum emissions that vent small volumes of methane and VOC at atmospheric pressure because the seal oil traps capture and recycle most of the seal gas upstream of the degassing drum would not be cost-effective. The final standards for NSPS OOOOb have been revised to be consistent with what is being required under the EG OOOOc presumptive standards. As such, the NSPS OOOOb final rule has been revised to include a new definition for a “centrifugal compressor equipped with sour seal oil separator and capture system” and requires that, in Alaska, such compressors be allowed to meet a performance-based volumetric flow rate standard of 9 scfm/seal. The volumetric flow rate of 9 scfm is an action level that, if exceeded, triggers the action of repairing or replacing the seal and is not a numeric limit.

H. Combustion Control Devices

In section X.H of this preamble, the final NSPS OOOOb and EG OOOOc requirements for combustion control devices are summarized. The rationale for the proposed requirements was presented in the December 2022 Supplemental Proposal in section IV.H. Combustion Control Devices. This section of the preamble presents a summary of significant comments received on the proposed requirements for combustion control devices and the EPA's response to those comments, as well as changes the EPA has made to the control device requirements since the December 2022 Supplemental Proposal. The EPA's full response to comments on the November 2021 Proposal and December 2022 Supplemental Proposal, including any comments not discussed in this preamble, can be found in the EPA's RTC document for the final rule.

1. Outlet Concentration Limit

Comment: Some commenters wanted to ensure that the concentration limit included in NSPS OOOOa for existing enclosed combustors will continue to be allowed in NSPS OOOOb and EG OOOOc. One commenter explained that destruction efficiency testing requires VOC sampling at the inlet and outlet of the control device but that many existing control devices do not have an inlet sampling port. The commenter notes that combined with the potential need to install additional monitoring equipment, allowing the use of a 20 ppm concentration limit will provide facilities that do not have inlet testing ports an alternative to meet compliance requirements for both NSPS OOOOb and EG OOOOc. Another commenter stated that the continuous monitoring option for organic compound concentration in the control device exhaust is meaningless without the corresponding outlet concentration performance standard. Additionally, the commenter requested that the EPA clarify how operators should handle compliance for existing control devices that are complying with the total organic compound concentration standard under NSPS OOOO or OOOOa.

Response: The EPA agrees that it is likely that most enclosed combustion devices that are being used to control affected facilities in NSPS OOOO and NSPS OOOOa demonstrate compliance during the performance test with the alternative outlet concentration limit instead of testing both the inlet and outlet of the control device. It remains the EPA's position that it is reasonable to allow owners and operators to continue to demonstrate compliance for these units with an outlet concentration. It is also plausible that owners and operators will have affected facilities under both NSPS OOOOb and EG OOOOc controlled by the same enclosed combustion device, and so we are adding the outlet concentration limit to both NSPS OOOOb and EG OOOOc.

In response to the comments received, the EPA is adding an outlet concentration limit of 275 ppm volume as propane on a wet basis to both NSPS OOOOb and EG OOOOc. This is the same outlet concentration limit that is in NSPS OOOO and NSPS OOOOa. We anticipate that carrying over this limit would not require a new performance test for most of these existing control devices until the next periodic performance test is due or until operation of the control device changes in a manner that warrants a new performance test.

2. Monitoring Flares

Comment: A commenter stated that while they support the requirements for no visible emissions and for monthly monitoring using EPA Method 22, the EPA could also consider alternative monitoring technologies and methods that would achieve equivalent or superior results. The commenter urged the EPA to also require flares and control devices to be monitored for compliance assurance during all fugitive emissions surveys, both under the OGI and AVO program and under the alternative periodic screening options. The commenter noted that control devices and flares, especially unlit and malfunctioning flares, are among the most observed and largest sources of methane emissions, and it is therefore critical that they are regularly inspected and monitored to ensure proper operation. The commenter further stated that multi-basin research has identified unlit flares across the entire country, and a Permian Basin study using flights conducted in 2020 found that 5 percent of all active flares were unlit. Moreover, the commenter contends that monitoring flares and control devices during fugitive emissions surveys poses very little additional burden and can ensure emissions events are avoided.

Response: The EPA agrees that requiring owners and operators to check flare operation during a fugitive emissions inspection adds little additional burden and can help to reduce the incidence of unlit flares. This is something some owners and operators already do in practice, because in reviewing reports submitted under NSPS OOOOa, we noted that many owners and operators listed flares in the fugitive emissions report. Additionally, for technologies used under the provisions of the periodic screening and continuous monitoring advanced methane detection technology work practices in the final NSPS OOOOb and EG OOOOc, we anticipate that by the nature of the operation of these technologies, these technologies will detect unlit flares. Therefore, requiring owners and operators to look at flares during an OGI inspection will also help to even the playing field for all technologies used in fugitive emissions monitoring. In the final rule, we are requiring owners and operators to view the operation of their flares with an OGI camera during fugitive emissions inspections conducted with OGI to ensure that the flare is lit and that there are no uncontrolled emissions coming from the flare. We are also requiring owners and operators to ensure that the flare is operating properly during AVO inspections by visually confirming that the pilot flame is lit and operating properly.

Comment: A commenter stated that with respect to the alternative to continuous flow monitoring, the EPA must include requirements to reassess the engineering assessment when there are changes to the sources vented to the flare, such as when additional sources are routed to the control device, or those upstream sources change, because the flow rate could increase, and proper destruction efficiency would not be ensured.

Response: The EPA agrees with the commenter that the assessment for maximum flow rate to an enclosed combustor or flare must be updated when there are changes to the device's operation that are expected to impact the initial assessment. We have revised the language in the final rule to reflect this requirement.

3. Visible Emissions Observations

Comment: Commenters suggested that the EPA should permit the use of cameras for operators to perform visual inspections of flare and combustor smoke under EPA Method 22. Visible light cameras such as security cameras are widely available and deployed at oil and gas sites, and they can be positioned such that they can view potential smoke from combustors and flares. Therefore, commenters request that the EPA clarify that operators can utilize visible light cameras to remotely observe flares and combustors for smoke and specify installation and operation requirements such cameras need to meet. Another commenter noted that video camera systems are allowed as an alternative to EPA Method 9 observation under broadly applicable approved Alternative Test Method 82 (ALT–082). Commenters also suggested that artificial intelligence and machine learning should be allowed to continuously screen the video feed for smoke detection and if smoke is detected, alert the operator that an EPA Method 22 follow-up is required.

Response: The EPA agrees that camera systems that monitor for visible emissions are a viable alternative to monthly EPA Method 22 observations for this sector, and there is already precedent for use of such systems in refineries under 40 CFR part 63, subpart CC. Therefore, the EPA has added the option to use a camera system for visible emissions observations to the final rule. In order for an owner or operator to use this option, the owner or operator must provide real-time, high-definition video surveillance camera output to the nearest control room or other continuously manned location where the camera images may be viewed at any time, with the output recorded continuously. The camera must be located at a reasonable distance above the flare flame and no further than 400 meters from the emissions source, at an angle suitable for visual emissions observations with the sun not in the field of view. With this option, observation via the video camera feed can be conducted readily throughout the day and will allow the operators of the flare to watch for visible emissions more frequently. The operator must document that they observed the camera feed for at least one minute each day. We note that this option is not the same as the digital opacity camera alternative outlined in ALT–082 which is not applicable in this rulemaking, as there is no opacity limit in the rule.

The EPA has not added an option that allows for automated viewing of the camera feed with artificial intelligence or machine learning, because we have no information demonstrating that these systems work effectively or under what circumstances these systems may encounter problems with adequately identifying visible emissions. Owners or operators are welcome to use such systems in addition to the requirements of the rule.

4. Measurement of NHV

Comment: Several commenters were concerned with the proposed NHV monitoring provisions for flares, which would require continuous monitoring of the NHV unless the initial NHV sampling demonstration (hourly sampling for 10 days) shows that the NHV is consistently above the applicable NHV value, which is dependent on the flare type. Commenters stated that the initial NHV sampling demonstration to show that the NHV of a gas stream is always above the required NHV in 40 CFR 60.18(b) is unnecessarily burdensome and is even more burdensome than what is required for refineries. Commenters suggest that the proposed initial NHV sampling demonstration as an alternative to continuous NHV monitoring should be simplified, because the NHV of vent streams from affected facilities is typically fixed or well above the minimum NHV requirements, as these vent streams consist of mostly hydrocarbons and the simplest hydrocarbon has a NHV of approximately 900 British thermal units per standard cubic foot (Btu/scf), which is well above the minimum NHV requirement proposed by the EPA. One commenter provided data collected from laboratories that analyze samples of associated gas and flared gas in North Dakota. Out of 7,774 gas samples collected and analyzed from 2020 through 2022, the average NHV was 1,459 Btu/scf, while the maximum and minimum values were 1,007 and 2,846 Btu/scf.

One commenter stated that since the vent streams from affected facilities are expected to have sufficient heating value, both the proposed continuous NHV monitoring and the initial NHV sampling demonstration are economically unreasonable. For the minimum NHV demonstration alternative, the commenter reports that the cost is expected to be $250,000 or more per demonstration. The commenter summarizes that the cost of a vendor-conducted 10-day continuous monitoring campaign for the initial NHV sampling demonstration is estimated at a minimum of $250,000 to $275,000 while the cost of 200 hourly samples is estimated at a total of $300,000 to $400,000 with an average cost per sample of $1,500 to $2,000 including shipping and analysis.

One commenter suggested that the EPA require a 10-day test period with one sample every 6 hours, for a total of 40 sample analyses. Another commenter proposed a simplified sampling protocol for samples to be taken twice a day for 7 days. A third commenter stated that the 10-day initial NHV sampling demonstration should be simplified to a single sample including the use of an appropriate, representative sample or an initial flare compliance assessment under 40 CFR 60.18, with the operator documenting why the sample is characteristic of the vent stream composition. After the initial NHV sampling demonstration, continuous compliance would be demonstrated through subsequent samples once every 3 years. The commenters also stated that neither the continuous NHV monitoring nor the initial NHV sampling demonstration alternative should be required if operators can demonstrate that the NHV is never expected to be below the minimum required value using a design evaluation or applicable engineering calculations including process simulation software and pressurized liquids sampling. One commenter stated that continuous monitoring of NHV presents inaccuracy issues associated with low or intermittent gas streams due to technological limits. While the commenter agrees with the availability of the initial NHV sampling demonstration in lieu of continuous monitoring, the commenter requested that the EPA allow operators to periodically ( i.e., quarterly) sample representative inlet gas streams to demonstrate compliance with any applicable heating value requirement for control devices used to control affected facilities with intermittent or low flow gas streams under this rule.

A different commenter stated that the EPA must require direct NHV monitoring at all oil and gas flares and combustion devices on a continuous basis. The commenter states the NSPS general provisions mandate that the Agency establish monitoring for the general provisions' NHV operating limits, especially since the general provisions themselves contain no monitoring requirements for this limit. The commenter also stated that the EPA correctly concludes that the current operating and monitoring practices and requirements for well sites and centralized production facilities are not adequate to ensure that flare control systems are operated efficiently. The commenter was concerned with the proposed alternative initial NHV sampling demonstration. The commenter suggested that 10 days of sampling cannot capture the variability of gas streams at oil and gas facilities, due in part to compositional variability, inert gases, and impurities in gas streams, and that it may not capture the lowest NHV streams, giving the false impression that these facilities are meeting the NHV operating limit when in fact they are not. The commenter also stated that the alternative to continuous monitoring is contradicted by findings the EPA has made regarding the great variability of gas compositions over short periods of time and the resulting dramatic effects on combustion efficiencies. The commenter contends that this alternative cannot ensure that flares and other control devices destroy 95 percent of VOCs and methane and that this alternative does not fulfill the requirements of 40 CFR 60.18(d).

Response: The EPA disagrees with the comments that neither continuous monitoring nor the initial NHV sampling demonstration (which the EPA proposed as an alternative to continuous monitoring) is unnecessarily burdensome or its cost unreasonable because the NHV value will always (or is expected to always) be above the NHV values that we proposed and are finalizing in this action. Specifically, we disagree with the commenters' assumption that the NHV value will always (or is expected to always) be above the minimum NHV values. As noted by a commenter, the variability of gas compositions can have a dramatic effect on the combustion efficiency of flares. This is especially true for streams that may contain large amounts of inert materials. Additionally, the EPA does not have data to support the assertion made by the commenter that continuous sampling systems have technological issues with sampling low and intermittent gas streams.

Nevertheless, in response to the comments received, the EPA has reevaluated the proposed alternative initial NHV sampling demonstration to see whether the burden can be reduced without compromising its adequacy. We do not think it is appropriate to allow quarterly sampling or a one-time sample, as suggested by some commenters, since there is some variability in the streams that are sent to flares and enclosed combustion devices which will likely be missed by not sampling daily. However, we are reducing the number of daily samples associated with the initial NHV sampling demonstration. Specifically, we are finalizing a requirement to conduct twice daily sampling for 14 days, reducing the total number of samples from 240 to 28. However, due to the significant reduction in the initial sampling, we need to confirm that the vent gas NHV remains above the required minimum value. Therefore, we are adding to the NHV demonstration alternative an ongoing compliance demonstration requirement to sample the vent gas to confirm that the NHV remains above the required minimum value. We are requiring three samples to be taken every 5 years. This ongoing demonstration timeline aligns with the timeline for conducting periodic performance tests of enclosed combustion devices, which is required every 5 years, so owners and operators who are using enclosed combustion devices to meet the applicable emission standards in this rule will be able to combine the NHV vent gas sampling with the performance test, which will help to reduce the burden associated with the ongoing compliance demonstration. Additionally, where associated gas from a well affected facility is the only inlet stream to the enclosed combustion device or flare, we are not requiring owners and operators to conduct continuous monitoring of the NHV or the alternative NHV sampling demonstration. In this case, because associated gas is high in methane content and similar in quality to sales grade gas, the NHV of the inlet stream to the enclosed combustion device or flare is considered to be sufficiently above the minimum required NHV for the inlet gas, and sampling is not needed to confirm the NHV of the inlet stream. With the changes discussed above, we believe that the burden of the NHV demonstration alternative in the final rule is much reduced since proposal.

While the EPA agrees with the comment that the variability of gas compositions can have a dramatic effect on the combustion efficiency of flares, the EPA disagrees with the commenter's contention that the alternative initial NHV demonstration is somehow contradicted by the EPA's prior statements in the proposed CAA section 112(d)(6) review for Miscellaneous Organic Chemical Manufacturing (84 FR 69203 (December 17, 2019)). The EPA notes that the great variability of gas compositions over short periods of time and the resulting dramatic effects on combustion efficiencies is especially true for streams that may contain large amounts of inert materials, such as nitrogen padding from storage vessels, which is common in the refining and chemical sectors. However, in general, we do not expect to see those situations in the upstream oil and gas sector, where most vent gas streams consist of high percentages of methane, which has an NHV well above the required minimum flare gas NHV. We also note that, in the preamble for the Miscellaneous Organic Chemical Manufacturing risk and technology review cited by the commenter, the flare discussion focused on flares that burn ethylene oxide and olefins/polyolefins. Olefins and polyolefins are more difficult to combust than the small, straight-chain hydrocarbons generally found in the upstream oil and gas sector. Therefore, the EPA does not believe that the alternative provided in the final rule is contradicted by the findings in the Miscellaneous Organic Chemical Manufacturing risk and technology review.

Comment: One commenter stated that some vent streams from affected facilities could potentially be below the minimum NHV requirement, including compressors in acid gas service or those at enhanced oil recovery facilities. The commenter notes that either situation could have high CO₂ content which would lower the NHV, so operators typically add assist gas or another vent stream with sufficient heating value to facilitate proper control device operation. In these limited situations, the commenter proposed that flow monitoring of the assist gas and vent streams should be allowed as an alternative to the continuous monitoring of NHV.

Response: The EPA disagrees that monitoring assist gas flow rates is an appropriate measure for ensuring proper combustion of inerts, as assist gas does not contain any heating value. Therefore, the introduction of assist gas will further reduce the heating value of the gas, possibly to a point where proper combustion cannot be sustained. Therefore, while monitoring or limiting assist gas is an important part of ensuring proper flare operation, the EPA does not believe that monitoring assist gas on its own can compensate for the drop in vent gas NHV caused by inerts or provide enough information for the owner or operator to ensure that proper combustion is occurring.

The introduction of inerts can greatly affect the NHV of the vent stream sent to a flare. While the EPA agrees that most flare gas streams at upstream oil and gas facilities will have no issue meeting the required minimum NHV on a continuous basis, we are concerned about situations where inerts may be introduced into the vent gas stream. To guard against the possibility of unacceptable flare gas NHV in these situations, we are including as part of the alternative NHV demonstration a requirement that owners and operators consider sources of inerts that may be sent to the flare, and that sampling must occur when the highest percentage of inerts are sent to the flare to ensure that NHV remains above the required minimum. If an owner or operator cannot ensure that the NHV remains above the required minimum due to the introduction of inerts, the owner or operator must continuously monitor the NHV of the vent stream.

5. Assisted Flares

Comment: A commenter urged the EPA to require any assisted flares in the oil and gas sector to meet an operating limit for the NHV in the combustion zone (NHVcz), as the EPA has done for flares at refineries and petrochemical sources. The commenter stated that, as the EPA found in its 2014–15 refinery NESHAP rulemaking, many studies have shown that the flare requirements in the general provisions cannot ensure that flares achieve 98 percent destruction efficiency, which is required under the refinery NESHAP. The commenter also referenced an Enforcement Alert the EPA distributed regarding flaring violations, in which the Agency recognized that certain needed parameters affecting the efficiency of flares are not captured within the general provisions, including maintaining the appropriate steam-to-vent-gas ratio and ensuring that the NHVcz is high enough to maximize combustion efficiency. The commenter explained that the EPA noted that reliance on the NHV of the vent gas—the parameter that the NSPS and NESHAP general provisions flare requirements use as an indicator of good combustion—ignores any effect of steaming. Therefore, the commenter stated that to incorporate steaming, a NHVcz is calculated to include the assist steam. The commenter stated that because complying with an operating limit for the heating value of the vent gas cannot ensure 95 percent or greater destruction efficiency of VOCs and methane by assisted flares, it is appropriate to update the flare requirements for any assisted flares to ensure proper destruction efficiencies. The commenter stated that the EPA must require owners and operators to comply with an operating limit for NHVcz and must promulgate monitoring requirements to ensure compliance with that limit.

Response: The EPA is aware that some companies are installing air-assisted flares to improve combustion efficiency, reduce smoking incidence of flares, and facilitate operation when inerts are added to the vent gas stream. We are still not aware of a prevalence of steam-assisted flares in this sector, but it is possible to over-assist an air-assisted flare. Therefore, in the final NSPS OOOOb, we are adding requirements to ensure that these flares are operated in a manner that will ensure good combustion efficiency, by adding operating parameters for NHVcz and the NHV dilution parameter (NHVdil). Specifically, the final rule includes the operating parameter values of 270 Btu/scf for NHVcz and 22 Btu/sqft for NHVdil that the EPA established for the petroleum refineries sector (40 CFR part 63, subpart CC). We recognize that these limits were intended to demonstrate compliance with a destruction efficiency of 98 percent and therefore are conservatively high for demonstrating compliance with the applicable standards in NSPS OOOOb. We have added provisions similar to those in 40 CFR 63.670(j)(6) which allow reduced monitoring for owners and operators with flare gas streams that have a consistent composition or a fixed minimum NHV. As stated above, we expect many flares in the upstream oil and gas sector to burn high NHV streams and anticipate that most owners and operators would be able to use these provisions. Additionally, for air-assisted flares, we have added provisions that allow a demonstration that based on the highest fixed or highest air-assist rate used, the device will meet or exceed NHVdil in lieu of continuously monitoring the air-assist rate.

We are not adding these requirements to the final EG OOOOc because we are concerned about the ability of existing sites to retrofit flares in order to meet these requirements. While we do expect that most owners and operators will be able to demonstrate compliance through flare assessments, those who cannot demonstrate compliance through an assessment will have to conduct continuous sampling of flare vent streams and flowrate monitoring of both the flare vent stream and the air assist stream. These accommodations can easily be made for a new flare. For an existing flare at an existing site, these retrofits require taking the flare out of service and may require adding ports to set up these monitoring systems. Additionally, there is no guarantee that ports can be placed at an appropriate location. Without additional information on assisted flares at existing sites and the ability of owners and operators to retrofit these flares, we are reluctant to place these requirements on existing sources, and as such, we are not adding these requirements to the final EG OOOOc.

6. Alternative Flare Monitoring

Comment: A commenter recommended that the EPA consider adding an alternative approach for monitoring flares that is more cost-effective and will achieve the same objective. The commenter pointed out that there have been significant advancements in the field of flare performance monitoring technology in recent years, including the Video Imaging Spectral Radiometry (VISR) technology which has been developed to remotely and directly monitor flare combustion efficiency and the Simplified VISR technology which has been developed to remotely monitor NHVcz for steam-assisted flares and NHVdil for air-assisted flares. The commenter noted that in November 2022 the EPA funded additional testing with focus on the Simplified VISR technology on both steam-assisted and air-assisted flares at the John Zink flare testing facility in Tulsa, Oklahoma. The commenter summarized the test results in exhibit 3 of their letter and stated that, based on these results, Simplified VISR technology can be easily deployed for a short-term study or long-term continuous monitoring of NHVcz for steam-assisted flares or NHVdil for air-assisted flares at a cost comparable to an OGI camera. The commenter requested that the EPA allow operators to use the Simplified VISR method to demonstrate compliance and give operators a choice between a calorimeter and the Simplified VISR. Additionally, if an operator chooses to do the 10-day initial NHV sampling demonstration instead of continuous monitoring of NHV, the Simplified VISR device could be installed to monitor the flare for 10 days and could operate autonomously and continuously—a significant advantage over manually collecting 200 hourly samples.

To facilitate the described alternative approach, the commenter stated, the flare NHV standard needs to be supplemented. The current NHV limit is based on the heat content in the gas stream that is fed to the flare, but the Simplified VISR measures NHVcz, which the commenter stated represents a better surrogate parameter for flare performance than vent gas NHV. To facilitate the Simplified VISR as an alternative to the proposed NHV limit, the commenter recommended that the final rule allow the operator to comply with the NHVcz and NHVdil limits promulgated in other rules. The commenter points out that these standards correspond to a combustion efficiency of 96.5 percent and a destruction efficiency of 98 percent, which is higher than the control efficiency required in the December 2022 Supplemental Proposal, representing a 60 percent methane emissions reduction (from 5 percent of the flared process stream down to 2 percent).

Response: The EPA notes that it has been reviewing the development of VISR to monitor flare combustion efficiency for several years. While we are not including it as an alternative in the final rule, as we have not yet developed a standard method for its use, the final rule provides a pathway to allow for the use of VISR, Simplified VISR, or other similar technology. In this pathway, an owner or operator could request an alternative test method to use a technology such as VISR that continuously monitors combustion efficiency or a technology such as Simplified VISR that continuously monitors NHVcz and NHVdil. The approval of such a request may be site-specific or may instead become broadly applicable, approved for a class of combustion devices, and listed on the EPA's website as an alternative test method.

To facilitate the pathway for potentially allowing these alternatives, the EPA is finalizing limits of 270 Btu/scf for NHVcz and 22 Btu/sqft for NHVdil. Destruction efficiency is a measure of how much of the hydrocarbon is destroyed, and combustion efficiency is a measure of how much of the hydrocarbon burns completely to yield CO₂ and water vapor. As such, combustion efficiency will always be less than or equal to the destruction efficiency. In the EPA's report on the development of parameters for properly operated flares, we stated that the relationship between destruction and combustion efficiency is not constant and changes with different compounds, but that we considered that a flare with a combustion efficiency of 96.5 percent achieved a destruction efficiency of 98 percent. We are uncertain if the relationship continues to hold at the same level as combustion efficiency continues to decrease. Therefore, in this final rule, which includes 95 percent emissions reduction standards, we are taking a conservative approach. If an owner or operator uses an alternative test method, such as VISR, to demonstrate compliance with the emissions reduction standards for a combustion control device and uses a test method that continuously monitors the combustion efficiency, we are requiring that the combustion device used to meet such standard have at least 95 percent combustion efficiency, as this will ensure a destruction efficiency of at least 95 percent.

In this final rule, owners and operators approved for an alternative test method that uses a technology that continuously monitors combustion efficiency or NHVcz and NHVdil would not be required to monitor flare vent gas flow rate or vent gas NHV. If the alternative test method uses a technology that continuously monitors combustion efficiency, the owner or operator would not be required to continuously monitor for the presence of a pilot flame or have an alert to the control room for the pilot flame. If the alternative test method uses a technology that can identify periods of visible emissions, the owner or operator would not be required to perform monthly EPA Method 22 observations. The EPA has also added a pathway to use an alternative test method to demonstrate continuous compliance with 95 percent combustion efficiency as part of the NHV initial sampling demonstration. In lieu of conducting vent gas NHV sampling during the initial demonstration period, the owner or operator would demonstrate that the combustion control device continuously achieves at least 95 percent combustion control, thus demonstrating that the heating values of the streams sent to the flare are consistently above the minimum level necessary to achieve proper combustion.

7. Other Changes to Control Device Requirements

Additionally, the EPA has made a number of clarifications and minor adjustments to the regulatory text in response to comments received:

• Revised 40 CFR 60.5412b(a)(1)(ii) and (f)(1)(vii)(D)( 1) to allow owners and operators to set the minimum temperature limit for combustion devices based on operation during the performance test.

• Revised 40 CFR 60.5412b(a)(1)(viii), 60.5412b(a)(3)(viii), 60.5413b(e)(2), 60.5415b(f)(1)(vii)(A)( 1), and 60.5417b(d)(8)(i) to add a requirement that an alert be sent to the control room when a pilot flame is no longer lit.

• Revised 40 CFR 60.5412b(a)(1)(ix), 60.5413b(e)(3), 60.5415b(f)(1)(vii)(A)( 2), and 60.5417b(d)(8)(v) to allow the duration of the visible emissions observation to be less than 15 minutes if the observer sees visible emissions for at least 1 minute prior to the end of the 15-minute period.

• Revised 40 CFR 60.5412b(a)(3)(vi) and 60.5417b(d)(8)(iv) and added 40 CFR 60.5415b(f)(1)(vii)(A)( 6) to clarify that the minimum flow rate requirement applies to both enclosed combustion devices and flares.

• Revised 40 CFR 60.5413b(b)(5)(ii) to allow control devices to be tested 30 days after returning to service if the control device is not operational at the time that a performance test is due.
• Revised 40 CFR 60.5413b(b)(5)(ii) to remove the conflict with 40 CFR 60.5413b(a) as to whether enclosed combustion devices must be periodically tested.
• Revised 40 CFR 60.5413b(d)(11)(iii) to indicate that when the manufacturer meets the testing requirements outlined for an enclosed combustion device, the control device will meet the requirement for 95.0 percent destruction of both VOC and methane.
• Revised 40 CFR 60.5413b(d)(12) to update submittal addresses.

• Revised 40 CFR 60.5413b(e), 60.5417b(d)(7), and 60.5417b(g)(6) to align the monitoring requirements for all enclosed combustion devices, regardless of whether they are tested by the manufacturer or the owner or operator.

• Revised 40 CFR 60.5417b(c) to clarify that monitoring systems that check for the presence of a pilot flame must record a reading at least once every 5 minutes and to clarify how to average monitored parameters.
• Revised 40 CFR 60.5417b(c)(2) through (4) to change site-specific monitoring plan to a company-defined area monitoring plan, to align the terminology with the terminology used for fugitive emissions monitoring.
• Revised 40 CFR 60.5417b(d)(8)(ii) to allow owners and operators the option to use gas chromatographs, mass spectrometers, and grab sampling systems to monitor NHV.
• Revised 40 CFR 60.5417b(d)(8)(ii) to exempt operators from conducting monitoring of NHV for associated gas routed to an enclosed combustion device or flare if the device or flare is receiving only associated gas (as defined in 40 CFR 60.5430b).
• Revised 40 CFR 60.5417b(d)(8)(iv) to change the required flow meter accuracy requirement from 2 percent to 10 percent in order to allow owners and operators additional metering device options and to reduce burden, considering the large range of flows that may be encountered in some control devices.
• Revised 40 CFR 60.5417b(d)(8)(iv) to clarify “line pressure” to “inlet line pressure.”
• Revised 40 CFR 60.5417b(d)(8)(iv) to change the terminology “backpressure preventer” to backpressure regulator valve and to add continuing operational and maintenance requirements for the backpressure regulator valve.
• Deleted 40 CFR 60.5417b(e)(2) in order to change the averaging time for gas flow rate from 1 hour to 3 hours to align with other operating parameters.
• Clarified the requirements for carbon adsorption systems in 40 CFR 60.5417b(f)(1).

I. Reciprocating Compressors

In section X.I of this document, the final NSPS OOOOb and EG OOOOc requirements for reciprocating compressors are summarized. The BSER analysis is unchanged from what was presented in the November 2021 Proposal (see 86 FR 63214–20, section XII.E. Proposed Standards for Reciprocating Compressors). However, significant comments were received on the December 2022 Supplemental Proposal on the following topics: (1) the EPA's proposal to format the performance-based volumetric flow rate standard of performance as a numeric standard, (2) scheduled-based packing replacement approach, (3) need to clarify that the standard is on a per-cylinder basis, (4) request that the EPA allow the alternative compliance option of routing to a control device in addition to routing to the process, and (5) the EPA's extension of requirements to reciprocating compressors located at centralized production facilities. For each of these topics, a summary of the proposed rule (where relevant), the comments, the EPA responses, and changes made in the final rule (if applicable), are discussed here. These comments and the EPA's responses to these comments generally apply to the standards proposed in both the NSPS OOOOb and EG OOOOc as the standards proposed under the NSPS OOOOb and EG OOOOc were the same. The EPA's full response to comments on the November 2021 Proposal and December 2022 Supplemental Proposal, including any comments not discussed in this preamble, can be found in the EPA's RTC document for the final rule.

1. Numeric Standard Versus Work Practice Standard

In reconsidering the BSER determination and standards for reciprocating compressors proposed in November 2021, the EPA recognized that it is feasible to prescribe a standard of performance, rather than a work practice standard, for reciprocating compressors. Accordingly, the EPA proposed a numeric emissions limit requirement in the December 2022 Supplemental Proposal. The major difference between that proposed standard and what the EPA proposed in November 2021 was that under the supplemental proposal, owners and operators would be required to maintain emissions at or below the emissions limit (emissions flow rate of 2 scfm) whereas under the November 2021 Proposal, owners or operators would have been required to replace rod packing only after discovering an exceedance of 2 scfm. The BSER was therefore proposed to be the replacement of the rod packing and/or other necessary repair and maintenance activities to maintain emissions at or below 2 scfm.

Comment: The EPA received several comments from industry that asserted that a numeric emissions standard in lieu of a work practice standard is unsupported and unworkable. One commenter stated that in the November 2021 Proposal, the EPA described a work practice standard that would require yearly monitoring and replacement of the rod packing when the measured emissions exceed 2 scfm. The commenter noted that the EPA cited the Natural Gas STAR document in the November 2021 Proposal that described a work practice approach for rod packing replacement. The commenter added that the work practice approach, including a 2 scfm threshold for triggering rod packing replacement, was further demonstrated at the EPA's November 2019 Natural Gas STAR and Methane Challenge Workshop. The commenter added that the California regulation cited by the EPA in the December 2022 Supplemental Proposal TSD is also a work practice standard with a 2 scfm threshold. The commenter stated that the December 2022 Supplemental Background TSD does not include any information to support an emissions standard rather than a work practice—and the November 2021 Proposal TSD envisioned a work practice standard. Thus, the commenter stated that if the EPA intended to propose an emissions limitation standard, the EPA gave no justification for, or analysis of, the change, which the commenter believed is arbitrary and capricious. The commenter believed that based on the two TSDs, it appeared that the EPA intended to propose a work practice standard that triggers rod packing maintenance when the threshold is exceeded. The commenter expressed that the extensive and case-by-case nature of rod packing replacement makes it particularly unsuitable for an emissions limitation standard.

Several commenters expressed concern that, as an emissions standard, the proposed rod packing requirements are unworkable. They explained that operators would be forced to decide between continuing to operate out of compliance until a maintenance shutdown can be scheduled or shutting down the compressor immediately to conduct the repair and venting or flaring gas that can no longer be compressed and transported during the unscheduled shutdown. The commenters added that a forced shutdown would likely result in significantly more emissions than continuing to operate until the next scheduled maintenance shutdown. For systems that are at capacity, shifting the incoming gas to another station is not a feasible or reliable option, resulting in additional flaring and venting, which is magnified given the time it takes to have producers shut in wells. According to one of the commenters, the December 2022 Supplemental Proposal made an incorrect assumption that the gas can simply be rerouted to other natural gas compression facilities, but the commenter explained that often that is not a possibility as piping is not in place to bypass a facility, or there may not be an alternative facility available. Another commenter added that while it is true that flow can be measured, it is not technically or economically practicable to install measurement systems that would assure compliance with a numeric emissions limitation. See CAA section 111(h)(2)(B).

A couple of commenters suggested that under a work practice framework (which they state to be the only supported option), companies be required to complete a corrective action within 720 hours of operation (equivalent to 30 days) and allow for delay of repair, similar to that for leak monitoring programs, of up to 2 years if repair goes beyond the replacement of rod packing. The commenters noted that exceeding the vent rate threshold after the time for corrective action would be a deviation, but exceeding the vent rate within the time allotted to correct would not.

One commenter stated that the EPA proposed to establish the 2 scfm flowrate as a not-to-exceed standard of performance, such that a violation occurs if flow rate exceeds that value (87 FR 74797). In doing so, the commenter suggested, the EPA fundamentally misconstrued the manufacturers' recommendations (on which the flow rate is based). In practice, the commenter explained, exceeding a manufacturer-recommended flow rate is an indication that a repair should be made. Exceeding that rate does not necessarily compromise operability of the unit and, in fact, the values are selected to allow continued operation for the period necessary to arrange for needed repairs to be made. According to the commenter, the EPA without explanation proposed to transform what in practice constitutes an action level into a regulatory cap that cannot be exceeded without the prospect of incurring a violation. The commenter argued that the EPA's proposal is at odds with the facts and is an unreasonable reinterpretation of standard maintenance practices.

The commenter argued that, if the EPA is intent on setting a numeric standard of performance, the value must be well above the 2 scfm that the EPA believes to be the standard manufacturer recommendations. They asserted that the value must accommodate operations for a reasonable and potentially significant period of time that may be needed to accomplish needed repairs. If the EPA takes this path, the commenter contended that a reproposal would be necessary so that commenters would know the newly proposed value, understand the EPA's rationale, and have an opportunity to submit comments on the record.

Response: The EPA acknowledges that the record for the 2 scfm performance volumetric flow rate standard supports a work practice standard and not a numeric standard. The EPA has determined that, for reciprocating compressors, the application of a measurement methodology to reciprocating compressors is not always practicable due to technological or economic limitations. It is not practicable here for an exceedance of the 2 scfm per cylinder volumetric flow rate to be a violation when the annual performance-based flow rate reflects whether there are performance issues with the rod packing that need to be addressed in order to take action to minimize the emissions/leak. This is similar to the basis and monitoring established for fugitive emissions component requirements, where a leak based on periodic monitoring triggers requirements to minimize the emissions/leak.

In the final rule, therefore, the 2 scfm performance-based volumetric flow rate standard will be implemented as a work practice standard and not as a numeric limit where an exceedance would be considered a violation. As such, the volumetric flow rate of 2 scfm is an action level that, if exceeded, triggers the action of repairing or replacing the rod packing and is not a numerical limit. Specifically, the final rule for reducing GHGs and VOC from new reciprocating compressors requires repair or replacement of the rod packing where, based on the required monitoring, the performance-based volumetric flow rate standard is exceeded. If the volumetric emissions measurement of the reciprocating compressor rod packing has a flow rate greater than 2 scfm (in operating or standby pressurized mode) or a combined rod packing flow rate greater than the number of compressor cylinders multiplied by 2 scfm, an owner or operator must repair or replace the reciprocating compressor rod packing within 30 calendar days after the date of the volumetric emissions measurement. Delay-of-repair provisions under a work practice standard appropriately recognize that the unit must be shut down to effect any such repair and replacement and that parts availability and supply chain disruptions may be relevant to how quickly the repair or replacement can be made. As such, the final rule allows for a delay of repair if the repair or replacement would require a vent blowdown, or it would otherwise be infeasible or unsafe, until the next process unit shutdown—specifically, if the repair or replacement (1) is technically infeasible, (2) would require a vent blowdown, (3) would require a process unit or facility shutdown, (4) needs to be delayed because parts or materials are unavailable, or (5) would be unsafe to repair during operation of the unit. In cases where there is a need for delay of repair, the repair must be completed during the next scheduled process unit or facility shutdown for maintenance, after a scheduled vent blowdown, or within 2 years, whichever is earliest.

2. Rod Packing Changeout Schedule-Based Approach

Comment: Several commenters expressed concern over the EPA's changing in the proposed NSPS OOOOb and EG OOOOc the requirements that the commenters have been meeting under NSPS OOOOa to replace rod packing on a fixed schedule. The commenters noted that given the uncertainties of the assumptions underlying the BSER evaluations for the two options (the rod packing changeout schedule-based approach and monitoring limit approach) and given that the cost effectiveness values of the two options are very close, they urged the EPA to provide flexibility to affected facilities by adopting both standards as BSER alternatives with the operator selecting their preferred approach.

According to one commenter, retaining the schedule-based approach is warranted because that compliance option has been implemented not only at NSPS OOOOa facilities but also through state regulations and voluntary actions by companies. The commenter added that the prescribed maintenance schedule is also an EPA-approved best management practice for the voluntary Methane Challenge program. Due to these EPA decisions, the commenter reported, many companies have “built out” reciprocating compressors rod packing maintenance programs using scheduled maintenance, including existing compressors not subject to the Federal mandate or state rules. The commenter expressed that it is critical that these existing and successful company programs not be supplanted by different requirements in NSPS OOOOb and EG OOOOc.

Several commenters noted specific suggestions with respect to a fixed schedule:

• Several commenters requested that the EPA allow rod packing replacement every 8,760 operating hours.

• One commenter requested that the EPA allow replacement annually or 8,760 hours (whichever comes first), which is similar in approach but more frequent than the current requirements in NSPS OOOO and NSPS OOOOa.

• Another commenter requested retaining the NSPS OOOOa approach, requiring the replacement of rod packing every 3 years or 26,000 hours of operation (if operating hours are monitored).

Several commenters requested that the EPA specify that where operators choose to replace rod packing on a fixed schedule, they are not required to measure volumetric flow rates.

Response: The contention by commenters that requiring the performance-based volumetric flow rate monitoring would result in owners or operators having to do more rod packing changeouts on reciprocating compressors and/or would lead to an increase in baseline maintenance/piston rod replacement to ensure proper operation of the compressor further supports requiring the performance-based volumetric flow rate monitoring standard over a fixed-schedule rod packing changeout every 26,000 hours to mitigate emissions. This is also consistent with the EPA's BSER determination that greater and more-efficient emissions reductions would be achieved by implementing an annual performance-based 2 scfm volumetric flow rate monitoring standard. For these reasons, the EPA is not including the 26,000-hour, fixed-schedule rod packing replacement as an alternative option to the condition-based 2 scfm volumetric flow rate monitoring option. However, under the final rule, the EPA has clarified that an owner or operator would be allowed to replace rod packing on or before 8,760 hours of operation after last rod packing replacement or monitoring and forgo the need to conduct the required performance-based volumetric flow rate monitoring. The final rule also specifies that owners or operators are allowed to forgo volumetric flow rate measurements if they replace the rod packing at or before 8,760 hours of operation after the last rod packing replacement or flow rate measurement.

The final rule has also been revised to state that the first volumetric flow rate measurements from a reciprocating compressor affected facility are to be conducted at or before 8,760 hours of operation after the effective date of the final rule ( i.e., 60 days after publication of the final rule in the Federal Register ), or at or before 8,760 hours of operation after the last rod packing replacement, or at or before 8,760 hours of operation after startup, whichever is later. Subsequent volumetric flow rate measurements from your reciprocating compressor are to be conducted at or before 8,760 hours of operation after the previous measurement that demonstrates compliance with the 2 scfm volumetric flow rate, or at or before 8,760 hours of operation after the last rod packing replacement, whichever is later. As an alternative to conducting required volumetric flow rate measurements, the final rule allows an owner or operator the option to comply by replacing the rod packing at or before 8,760 hours of operation after the effective date of the final rule, at or before 8,760 hours of operation after the previous flow rate measurement, or at or before 8,760 hours of operation after the date of the most recent compressor rod packing replacement, whichever is later.

3. Clarification That the Standard Is Based on a Per-Cylinder Basis

Comment: Several commenters requested clarification that the volumetric standard applies to each rod packing (or throw) or set of packing and not to the entire compressor and that the rule text clearly addresses manifolded vents on a combined basis. The commenters cite the precedent set by the CARB where reciprocating compressors in California are restricted to 2 scfm per rod packing, and not per compressor, as set forth in 17 CCR section 95668(c)(4)(D), Greenhouse Gas Emission Standards for Crude Oil and Natural Gas Facilities (allowing for “a combined rod packing or seal emission flow rate greater than the number of compression cylinders multiplied by two (2) scfm”) which states:

(6) with a rod packing or seal with a measured emission flow rate greater than two (2) standard cubic feet per minute (scfm), or a combined rod packing or seal emission flow rate greater than the number of compression cylinders multiplied by two (2) scfm.

These commenters generally stated that this approach makes sense and is consistent with the proposed BSER from the November 2021 Proposal. In addition, the EPA based its proposal to measure the flow rate of each cylinder on volumetric emission factors used in the 1996 EPA/GRI report quantifying methane emissions from the U.S. natural gas industry—which the EPA notes are per cylinder. The commenters elaborated on why they believed that this was the EPA's intent and several commenters provided in-line regulatory text changes where they believed the clarification was needed.

Response: The EPA agrees that the basis and intent of the standard is that it be applied on a per-cylinder basis and that clarity was needed in both the NSPS OOOOb and EG OOOOc regulatory text. The final rule regulatory text has been revised to make this clear as suggested by the commenters. Specifically, clarifying changes have been made to: 40 CFR 60.5385b, paragraphs (a) through (c) of NSPS OOOOb; and 40 CFR 60.5393c, paragraphs (a) through (c) of EG OOOOc.

4. Routing to Process or Control Device

In the December 2022 Supplemental Proposal, the EPA proposed to allow an alternative reciprocating compliance option of routing rod packing emissions to a process via a CVS. Several commenters requested that they also have the option to use proven add-on controls, such as an existing combustor or flare, in addition to routing to a process. A commenter explained that such options may be key for existing units and units that are modified or reconstructed.

Comment: A few commenters provided several reasons for why it may not always be feasible to route rod packing vents back to the process:

• Depending on the pressure differential between nearly ambient rod packing vents and pressurized piping, substantial horsepower may be required to achieve capture.
• Recompression designs require substantial horsepower and could require gas engines of variable horsepower to achieve the recompression, negating some of the emissions reductions this rule seeks to achieve.
• Currently available rod packing capture systems attempted by Williams and others in the industry have performed poorly or are ineffective in certain applications or configurations.

• Rod packing vents are essentially at ambient pressure, creating a situation where oxygen (O₂) could be introduced into the process gas, leading to safety concerns.

• The gas quality in the rod packing vents may not be compatible with the only technically feasible location in the process, based on pressure differentials, for the gas to be routed. For example, if the gas in the compressor is sour gas, but the only technically feasible place for the gas to be absorbed in the process is the fuel gas system, the sour gas is often not a good candidate for fuel gas use due to the detrimental effect on components.

According to one commenter, currently available rod packing capture systems that have been attempted by the commenter and their members have not performed as intended and, in some applications, have not worked at all. They explained that even if these systems were as effective as advertised, timing is a significant concern as the supply is not currently available to meet demand. The commenter recommended that where rod packing vents are routed to a control device, the EPA could require that the flow be measured every 26,000 hours of operation. The commenter noted that this would ensure that rod packing is appropriately maintained while overall emissions are greatly reduced.

Another commenter provided that the incremental benefit achieved between monitoring and subsequent repair (if applicable) versus capturing and venting to a control device that achieves 95 percent destruction efficiency has not been substantiated by the EPA within its BSER analysis. This, according to the commenter, is especially true for any compressor that already is designed and configured to route rod packing emissions to a flare or other combustion device.

Response: The EPA evaluated allowing the alternative option of routing to a control device that achieves 95 percent control of emissions and has determined that it would be acceptable as an alternative control option. The volumetric 2 scfm performance-based volumetric flow rate standard is estimated to reduce VOC and methane emissions by approximately 92 percent, and a flow rate of 40 scfm reduced by 95 percent would meet a 2 scfm flow rate. As a result, we have concluded that allowing for routing to a control device achieving a 95 percent reduction in VOC and methane emissions has merit and would provide equivalent or better emissions reduction compared to BSER. Accordingly, we have included this measure as an alternative option for compliance in the final rule.

5. Applicability of Requirements to Compressors Located at Centralized Production Facilities

The EPA proposed (86 FR 63184–85, November 15, 2021) to define centralized production facilities separately from well sites because the numbers and sizes of equipment, particularly reciprocating and centrifugal compressors, are larger than for standalone well sites, which would not be included in the proposed definition of “centralized production facilities.” In the 2016 NSPS OOOOa, the EPA exempted reciprocating and centrifugal compressors located at well sites from the applicable compressor standards. Reciprocating compressors that are located at well sites are not affected facilities under the 2016 NSPS OOOOa. The EPA previously excluded them because the EPA found the cost of control to be unreasonable. 81 FR 35878. However, we believed the definition of “well site” in NSPS OOOOa may have caused confusion regarding whether reciprocating compressors located at centralized production facilities were also exempt from the standards, which was not our intent.

To clarify our intent, we proposed to define centralized production facility as follows in the December 2022 Supplemental Proposal:

Centralized production facility means one or more storage vessels and all equipment at a single surface site used to gather, for the purpose of sale or processing to sell, crude oil, condensate, produced water, or intermediate hydrocarbon liquid from one or more offsite natural gas or oil production wells. This equipment includes, but is not limited to, equipment used for storage, separation, treating, dehydration, artificial lift, combustion, compression, pumping, metering, monitoring, and flowline. Process vessels and process tanks are not considered storage vessels or storage tanks. A centralized production facility is located upstream of the natural gas processing plant or the crude oil pipeline breakout station and is a part of producing operations.

Additionally, we proposed to define the affected facility as:

(c) Each reciprocating compressor affected facility, which is a single reciprocating compressor. A reciprocating compressor located at a well site is not an affected facility under this subpart. A reciprocating compressor located at a centralized production facility is an affected facility under this subpart.

For purposes of analyses, we proposed to determine that it was appropriate to apply the same emission factors to reciprocating compressors located at centralized production facilities as those used for reciprocating compressors at gathering and boosting compressor stations. Given the results of that analysis, the EPA proposed to apply the proposed NSPS OOOOb requirements to reciprocating compressors located at centralized production facilities. At that time, the EPA proposed a new definition for centralized production facilities to distinguish compressors at standalone well sites where the EPA has determined that the standard should not apply.

Comment: One commenter requested that the EPA clarify the applicability of compressor standards to well sites. The commenter stated that the definition proposed for “centralized production facility” may extend applicability to compressors located at well sites, which have historically been exempt from the compressor standards. The commenter noted that the EPA had not updated its cost analyses with new information with respect to well sites and believed that extending applicability to well sites was not the EPA's intent.

Another commenter urged the EPA to keep the current compressor exemptions shown in both subparts NSPS OOOO and NSPS OOOOa. The commenter specifically requests that the EPA maintain that each compressor “located at a well site, or an adjacent well site and servicing more than one well site, is not an affected facility.”

Conversely, another commenter supported the EPA's proposed definition of a centralized production facility and supported the extension of compressor standards to these sites. While the GHGI does not contain data on the number of compressors in the production segment, the commenter reported that they analyzed data submitted in response to the EPA's 2016 ICR to assess the number of compressors across different facility types in the production segment. While the ICR data are not a full inventory, the commenter contended that the ICR illustrates that there are a significant number of compressors utilized in the production segment, with most reciprocating compressors located at centralized production facilities.

A couple of commenters recommended that the EPA continue the exemption of each centrifugal and reciprocating compressor “located at a well site, or an adjacent well site and servicing more than one well site” as provided in both 40 CFR part 60, subpart OOOO, and 40 CFR part 60, subpart OOOOa. The commenters explained that well operators visit and service these wells and associated compressors daily to inspect for proper operation, to inspect for leaks, and to conduct maintenance and repairs activities. Any necessary repairs are implemented as soon as possible to avoid product loss and to maximize profit returns. If the EPA wishes to propose monitoring for well site compressors, the commenters recommended that the EPA allow the more feasible and cost-effective monthly AVO inspection and documentation, similar to the requirements allowed under 40 CFR 60.5416a.

Some commenters expressed that applying the proposed monitoring requirements to reciprocating compressors located at “centralized production facilities” may be beneficial in certain operations and where larger oil and gas operators may have the resources and equipment to monitor those emissions. However, they suggested that it should be an option/alternative and not a mandatory requirement, as it may unnecessarily create additional burdens and costs for smaller operators that send production from several marginal/low production wells to a “centralized production facility.” These commenters reported that, for marginal/low production well operators, centralized production facilities may be more cost-efficient than having equipment at each well site and this practice reduces overall the environmental footprint of the operation. The commenters suggested that it would be an unnecessary additional cost on small businesses and that it disincentivizes the use of centralized production facilities in this scenario. The commenters requested that the EPA remove this requirement for marginal/low production wells that send production to centralized production facilities.

Response: Most of these comments were based on the November 2021 Proposal prior to the EPA's December 2022 Supplemental Proposal definitions cited earlier in this document for a reciprocating compressor affected facility and centralized production facility. The EPA has finalized the December 2022 Supplemental Proposal's proposed requirements related to the definitions of the reciprocating compressor affected facility and centralized production facility. Some of the commenters suggested that, by extending requirements to apply to centralized production facilities, the EPA was extending requirements to well sites where reciprocating compressors were not previously regulated. That interpretation confirms that clarity was needed. Based on the proposed definition of the reciprocating compressor affected facility, in addition to the proposed definition for centralized production facility as proposed in the December 2022 Supplemental Proposal, we believe that we clarified our intent. That intent is that reciprocating compressors located at well sites are not subject to requirements. However, reciprocating compressors located at centralized production facilities that consist of equipment at a single surface site used to gather, for the purpose of sale or processing to sell, crude oil, condensate, produced water, or intermediate hydrocarbon liquid from one or more offsite natural gas or oil production wells (including reciprocating compressors) are subject to reciprocating compressor requirements.

In response to the commenters that noted that small operators of marginal/low production wells often send production from several marginal/low production wells to a “centralized production facility” because it is uneconomic to have equipment at each well site, the EPA does not understand why they would no longer be incentivized not to have equipment at each well site. The commenters did not provide sufficient information as to why an owner or operator of reciprocating compressors at centralized production facilities would not continue having reciprocating compressors at centralized production facilities because they would be subject to requirements in lieu of having equipment at each well site.

J. Storage Vessels

In section X.J of this document the final NSPS OOOOb and EG OOOOc requirements for storage vessels are summarized. In the November 2021 Proposal, the EPA proposed that for NSPS OOOOb, a storage vessel affected facility is a tank battery, which can be a single tank, with the potential to emit equal to or greater 6 tpy VOC or 20 tpy methane. The EPA proposed that an owner or operator of a tank battery must determine the potential for VOC and methane emissions using a “generally acceptable model or calculation methodology” that accounts for flashing, working, and breathing losses. The EPA proposed that the determination may take into account requirements under a “legally and practicably enforceable limit” in an operating permit or other requirement established under a Federal, state, local, or Tribal authority and proposed specific elements as to what constitutes a “legally and practicably enforceable limit.” The elements included: a quantitative production limit and quantitative operational limit(s) for the equipment, or quantitative operational limits for the equipment; an averaging time period for the production limit, if a production-based limit is used, that is equal to or less than 30 days; established parametric limits for the production and/or operational limit(s), and where a control device is used to achieve an operational limit, an initial compliance demonstration ( i.e., performance test) for the control device that establishes the parametric limits; ongoing monitoring of the parametric limits that demonstrates continuous compliance with the production and/or operational limit(s); and recordkeeping and reporting by the owner or operator that demonstrates continuous compliance with the limit(s). In the November 2021 Proposal, the EPA proposed that a tank battery is a group of storage vessels which are physically adjacent and that receive fluids from the same source or that are manifolded together for liquid or vapor transfer. Regarding BSER, the EPA proposed that storage vessel affected facilities must reduce emissions by 95 percent or greater. The BSER analysis is unchanged from what was presented in the November 2021 Proposal (see 86 FR 63199–201, section XII.B. Proposed Standards for Storage Vessels). The EPA proposed similar requirements for designated facilities under EG OOOOc, which have the potential to emit greater than or equal to 20 tpy methane.

In the November 2021 Proposal, the EPA proposed specific actions that would constitute “modification” of an existing tank battery for purposes of determining whether NSPS OOOOb is triggered (if the potential methane or VOC emissions are determined to be above the applicability threshold). Some of the actions that could trigger modification are actions that occur at the well site, such as refracturing a well or adding a new well that sends these liquids to the tank battery. The EPA did not propose specific provisions for reconstruction in the November 2021 Proposal.

In the December 2022 Supplemental Proposal, the EPA proposed a revised definition of storage vessel affected facility. In response to comments on the November 2021 Proposal, the EPA removed the criterion that the storage vessels in the tank battery are physically adjacent and the criterion that the vapor lines are manifolded together.

In the December 2022 Supplemental Proposal, the EPA retained the same provisions for “legally and practicably enforceable” criteria which were proposed in the November 2021 Proposal. Regarding modification and reconstruction, to address the resultant emissions at a compressor station or onshore natural gas processing plant receiving those liquids, where the emissions have already been accounted for in the permit, in the December 2022 Supplemental Proposal, the EPA proposed that for compressor stations or onshore natural gas processing plants, the modification trigger occurs when the tank battery receives additional fluids which cumulatively exceed the throughput used in the most recent determination for VOC or methane emissions ( e.g., permit) based on the design capacity of such tank battery. In addition, the December 2022 Supplemental Proposal retained the November 2021 criteria that a modification is also triggered when a storage vessel is added to an existing tank battery and/or one or more storage vessels are replaced such that the cumulative storage capacity of the existing tank battery increases. In the December 2022 Supplemental Proposal, the EPA proposed two actions which constitute reconstruction: over half of the storage tanks are replaced in an existing tank battery that consists of more than one storage vessel; or the provisions of 40 CFR 60.15 are met for the existing tank battery that consists of a single storage vessel.

The EPA received significant comments on the definition of legally and practicably enforceable limits, modification, and reconstruction. This section of this preamble presents a summary of those significant comments and the EPA's response to those comments. These comments and the EPA's responses to these comments apply to the standards proposed in both the NSPS OOOOb and EG OOOOc. The EPA's full response to comments on the November 2021 Proposal and December 2022 Supplemental Proposal, including any comments not discussed in this preamble, can be found in the EPA's RTC document for the final rule.

1. Legally and Practicably Enforceable Limits

As explained in the preamble to the November 2021 Proposal (86 FR 63201), from its years of experience of reviewing permits of legally and practicably enforceable limits, the EPA has long been aware that many owners and operators claim that storage vessels are not affected facilities under 40 CFR 60.5365(e) and 40 CFR 60.5365a(e) by alleging that the VOC emissions are less than 6 tpy. Since promulgation of NSPS OOOO in 2012, the EPA has expended extensive resources in enforcement actions nationwide to review permits, general permits, and permits-by-rule for storage vessels and found that, in nearly in all cases, across nearly 400 storage vessels, these permits or other requirements are not legally and practicably enforceable. In nationwide ongoing enforcement actions, the EPA continues to find permits or permits-by-rule that are not legally and practicably enforceable. The EPA has repeatedly expressed this concern in prior rulemaking actions. See, e.g.,83 FR 52085 and 85 FR 57425. The EPA believes that the new criteria being finalized in this action will help to ensure that storage tank batteries that rely on legally and practicably enforceable limits to claim nonapplicability of NSPS OOOOb or EG OOOOc indeed have potential emissions below the relevant applicability threshold(s).

As discussed in this section, several commenters failed to acknowledge the EPA's concern, claiming that it does not exist; some commenters insist that the criteria are unnecessary but do not offer any alternative to address the EPA's concern. The EPA has provided examples of limits that are not legally and practicably enforceable later in this section and is finalizing the criteria as proposed to ensure that, where an owner and operator is taking into account a legally and practicably enforceable limit in determining the applicability of the storage vessels standards under OOOOb or EG OOOOc, those limits actually limit and maintain potential emissions below the rule's applicability thresholds under NSPS OOOOb or designated facilities under EG OOOOc. The EPA further notes that including legally and practicably enforceable limits is an option, not a requirement, in determining storage vessel affected facility/designated facility status under NSPS OOOOb and EG OOOOc. The EPA will continue to evaluate the use of permit limits in determining the applicability of the standards for storage vessels pursuant to the criteria finalized in this action to see whether the EPA's concern is fully addressed. If concerns about the enforceability of the applicability criteria for the storage vessel standards remain upon implementation of the revised regulatory provision, the EPA may initiate further rulemaking in the future.

a. Need for a National Rulemaking To Address LPE Across CAA Programs

Comment: Several commenters urged the EPA to defer final action on the proposed definition of legally and practicably enforceable limits until such time as the Agency undertakes a national rulemaking. A few of the commenters pointed out the potential for inconsistencies among the various CAA programs that similarly require legally and practicably enforceable limits to determine applicability ( e.g., an effective emissions limit used to avoid major NSR permitting might, at the same time, not be effective for purposes of the NSPS OOOOb and/or EG OOOOc storage vessel standards). One commenter opined that what constitutes an acceptable and effective “legally and practicably enforceable limit” has been an open question since the mid-l990s, when the prior “Federal enforceability” requirement was remanded or vacated across the EPA's programs. Similarly the commenter believed that these proposed provisions of the NSPS OOOOb and EG OOOOc were driven by a July 2021 report from the EPA Inspector General that criticized the EPA for not responding to these judicial decisions. The commenter stated that the EPA's announced plan to establish national rules for effective limits on PTE and to do so in the relative near future lends strong additional support to the view that the EPA should not address these issues in a premature and piecemeal fashion. Another commenter stated that a national rulemaking would avoid many potential inconsistencies and uncertainties across CAA programs and would allow the EPA to establish reasonable transition rules so that affected sources and states have time to revise existing emissions limitations as needed to meet the new effectiveness criteria.

Response: The final rule includes “legally and practicably enforceable” criteria specific to oil and gas storage vessels. The EPA is choosing to add regulatory certainty to describe legally and practicably enforceable emissions limitations to address a common problem that the EPA has observed over the past decade through implementation of NSPS OOOO and OOOOa. Specifically, the EPA has identified problems with permits that states and owners and operators have characterized as legally and practicably enforceable. As discussed in the November 2021 Proposal (see 86 FR 63201) and elaborated in section XI.J.1 of this document, when the EPA has reviewed the limits considered by facilities as legally and practicably enforceable, the limits are often of such a general nature as to be unenforceable or otherwise lack measures to ensure the required emissions reduction. Unless the compliance with the permit limit can be determined, and the permit limit achieves the desired emissions reductions, they are not meaningful requirements. Excerpts of specific permits that the EPA has reviewed and determined to be lacking legally and practicably enforceable limits include:

Permit 1—Applicable Emissions Limitations or Control Measures

• In order to comply with the tons-per-month emissions limit, utilize one or more of the following controls: Use of add-on control (vapor recovery, flare, or equivalent) to control emissions from storage vessels as needed to comply with the annual VOC emissions limitations.
• The permittee accepts a voluntarily limit to restrict the potential VOC emissions from each storage vessel to less than 6 tpy.

In Permit 1, the control device is not specified and the permit terms do not specify a destruction rate efficiency, combustion rate, or availability for a VRU. The provision also does not specify emissions testing, operational parameter monitoring, inspection requirements, or recordkeeping or reporting requirements for the add-on control. Additionally, the terms “voluntarily limit” in the second provision indicate that controlling emissions below 6 tpy of VOCs is not a requirement.

Permit 2—Combustor/Flare Requirements

• All exhaust gas/vapors from the oil storage tanks must be routed to the operating combustor/flare.
• The combustor/flare shall operate with no visible emissions.
• Visual determination of smoke emissions from flares shall be conducted according to 40 CFR 60, appendix A, EPA Method 22.

In Permit 2, a destruction rate efficiency of 95 percent or greater is not specified. There is no testing requirement for the control device, no continuous pilot light monitoring or inspection requirement, no indication of how frequently EPA Method 22 inspections must be conducted, and no recordkeeping or reporting requirements. Both Permit 1 and Permit 2 demonstrate provisions from permits that do not have operational or parametric limits and therefore that the EPA has determined not to be legally and practicably enforceable and thus adequate to ensure that the storage vessels are below the applicability thresholds for the applicable standards.

The EPA disagrees that it should delay establishing the criteria for legally and practicably enforceable limits for purposes of determining storage vessel affected facility/designated facility status under NSPS OOOOb and EG OOOOc until such time as the Agency undertakes a national rulemaking on legally and practicably enforceable limits for other CAA provisions. The criteria in this final rule are unique and specifically tailored toward their intended purpose, which is to ensure that limits that are being taken into account in determining NSPS OOOOb and EG OOOOc applicability do in fact cap the potential emissions of a tank battery below the relevant applicability threshold and are enforceable. There is no reason why the EPA needs to wait to address this long-observed issue with respect to this emission source. Moreover, general criteria for legally and practicably enforceable limits would not necessarily provide the clarity and certainty that is necessary to ensure that the issue observed in the implementation of NSPS OOOO and OOOOa does not continue in the future in the implementation of NSPS OOOOb and EG OOOOc. Nor would such general criteria be timely, given the NSPS OOOOb standards will apply upon the effective date of this action and states will need to begin developing state plans pursuant to EG OOOOc. Finalizing the criteria now will provide states and sources specificity and certainty as to what the EPA considers legally and practicably enforceable for purposes of determining potential tank battery emissions under NSSP OOOOb or a state or Federal plan implementing EG OOOOc. The EPA believes that this level of specificity and certainty will serve to guide states and sources in establishing permit limits for tank batteries that could be used in determining NSPS OOOOb/EG OOOOc applicability.

b. LPE and Delegated Authorities

Comment: The EPA received multiple comments regarding the interplay with delegated authorities other than the EPA, such as concern that existing permits may not comply with the criteria proposed by the EPA, how the criteria align with permit-by-rule or permits, and the fact that many existing state permits lack methane limits.

Some commenters expressed concern with the proposed definition for the term “legally and practicably enforceable” as it relates to state emissions limits for “storage vessel affected facilities” that limit their potential for VOC emissions below 6 tpy. One commenter believed that in effect, if the EPA deems applicable state standards not “legally and practically enforceable,” it would disregard the state limits and treat the storage vessels as uncontrolled for purposes of Federal regulation. The commenter was concerned that this proposal thus has the potential to create substantial friction between the EPA and the states and could result in many more facilities becoming subject to Federal emissions standards.

Another commenter opined that where a rule contains an emissions threshold under which a given piece of equipment is not subject to the rule's requirements, it is fair and logical that the equipment be considered outside of rule coverage where emissions controls or limitations are in place to keep emissions below the threshold, even though in an uncontrolled state the equipment is capable of producing emissions above threshold levels. The commenter was concerned that that an owner or operator would be unable to claim the existence of legally and practicably enforceable limits or throughput limitations keeping a storage vessel below the applicability threshold if they are unable to coordinate with the applicable permit authority to work out specific limits, monitoring requirements, and recordkeeping that will ensure that any permitted emissions limit is achieved. The commenter also pointed out that some programs do not have minor source permitting programs allowing for inclusion of GHG emissions. The commenter summarized that a permit limit is a permit limit, and it is inconceivable that there is any Federal, state, or local permit that does not carry with it the ability of the issuing authority to ensure and enforce compliance if permit limits are exceeded. The commenter stated that they recognize that reporting, recordkeeping, and monitoring requirements will vary from permit to permit, but that all permits ultimately must be complied with or enforcement consequences from the issuing authority may follow. To the commenter's knowledge, they stated, there is no permit that does not contain consequences for violations.

Another commenter likewise was concerned that existing permits in many states may not meet the criteria that the EPA is proposing for legally and practicably enforceable permit terms and believes that the proposed changes will require states to review and revise countless permits and also may require states to engage in rulemakings over and above the efforts states will be required to initiate to implement these rules. The commenter stated that the EPA has neither explained nor justified this policy change, as it must, and should retract it. Another commenter stated that the proposed criteria for legally and practicably enforceable limits provide no additional benefit and pose several permitting problems.

Similarly, another commenter believed that states are much better equipped to determine the appropriate methods for the specific circumstances facing industries within their state and that process is required under the EPA's regulations (when the states meet certain conditions). The commenter was concerned that the proposed requirements conflict with the approach used in both the title V and NSR/PSD permitting programs. Under these programs, the commenter explained, operators may rely on control requirements to limit their PTE that would no longer be available under the proposed rule. In effect, the commenter was concerned, the proposed rule would arbitrarily require operators to have two different PTE calculations—one for title V and NSR permitting and another for NSPS/EG under this rule. The commenter stated that the definitions of “potential to emit” and “federally enforceable” show that the EPA's own regulations provide states with substantial latitude to establish “legally enforceable procedures.” The commenter cited to 40 CFR part 51 for the definition of “potential to emit” and “federally enforceable” and concluded that the TCEQ (Texas Commission on Environmental Quality) emissions limits, established under its EPA-approved SIP, are by the EPA's own part 51 definitions, federally enforceable. The commenter further noted that the EPA previously determined that the regulations and permits issued by both the TCEQ and the NMED (New Mexico Environment Department) were legally and practicably enforceable. The commenter also stated that in the preamble to the proposed 2013 amendments to NSPS OOOO, the EPA reviewed the regulations in several states to determine which states already had storage tank control requirements for calculating PTE. Based on its evaluation of these regulations, the commenter stated, the EPA determined that several states already had legally and practicably enforceable regulations, including both Texas and New Mexico, such that the EPA could subtract the storage vessels in these states “from the overall count of storage vessels that would be subject to the final rule.” The commenter believed that the EPA's proposal to require a new definition of “legally and practicably enforceable” substitutes its own judgment as to what is legally and practicably enforceable when its own regulations say that determination should be left to the states, subject to the EPA review. This commenter and another commenter suggested that the SIP review process is the appropriate mechanism as opposed to attempting to make changes in this regulation. The commenter believed that, when given the opportunity to review the regulations of Texas and New Mexico with regard to calculating PTE, the EPA already has determined that those regulations were federally enforceable.

Among other concerns, some commenters noted that sources do not have methane limits in permits and that prohibiting the use of permits-by-rule and general permits would impose enormous burdens on sources and delegated state authorities, for which the proposal makes no provision. One commenter was concerned that this prohibition would have a cascading effect on title V determinations across numerous sources, imposing substantial additional burdens and complexities on sources and states. The commenter stated that if the EPA decides to finalize the text, the EPA should recognize that sources in good faith went to the regulator and obtained a permit under the applicable state minor source program and thus, at a minimum, the commenter stated, the EPA should provide flexibility by phasing in the requirement and applying the new definition only when a source needs to apply for a new or revised permit or a permit renewal. Moreover, crucially, for all existing sources, the commenter stated that the EPA should be clear that existing permits authorizing a source to operate remain fully effective, pending state processing of new permits.

Another commenter similarly believed that the proposed revisions are inconsistent with the EPA's reliance on states to administer the CAA with regard to title V and PSD. That is, the commenter stated, the EPA allows states to establish emissions limits for sites to keep their emissions below title V and PSD permitting thresholds. Monitoring, recordkeeping, and reporting requirements in a permit should be tailored to align with the level of authorization, with minor sources having fewer requirements than major sources, according to the commenter. The commenter recommended that for streamlined permitting mechanisms, such as Permits by Rule in Texas, the state agency would have to engage in rulemaking before operators could rely on such permits for determining storage vessel and tank battery PTE. Such rulemaking could take months to years, meaning that operators cannot rely on legally and practicably enforceable limits until those rule updates are finalized and effective, according to the commenter.

Response: The EPA recognizes that current permits for NSPS OOOO and OOOOa sources may not entirely meet the criteria that the EPA is finalizing for legally and practicably enforceable limits for purposes of NSPS OOOOb and EG OOOOc. The EPA disagrees, however, that the final rule necessitates that all existing permits be rewritten. These specific criteria do not retroactively apply to permit limits or other requirements that owners and operators had previously relied upon in determining NSPS OOOO or OOOOa applicability to their storage vessels. The criteria will apply when determining NSPS OOOOb applicability to new storage vessels, i.e., those for which construction, reconstruction, or modification commenced after December 6, 2022, and when determining applicability for existing storage vessels covered by the yet-to-be-developed state plans implementing EG OOOOc. For new storage vessels constructed, reconstructed, or modified before the effective date of this final rule, to the extent their owners or operators decided to obtain legally and practicably enforceable limits to cap the potential emissions from their storage vessels below the proposed NSPS OOOOb applicability thresholds, those owners or operators were on notice of the EPA's proposed LPE criteria when obtaining such limits. Accordingly, the EPA does not agree that it is necessary to provide a transitional period for sources to obtain or revise permits before applying the new LPE criteria for determining applicability of the storage vessel standards under NSPS OOOOb or under future state and/or Federal plans implementing EG OOOOc.

With regard to existing sources, the EPA notes that existing permits for designated facilities will need to be reopened to include legally and practicably enforceable methane emission limits to the extent facilities want to take into account such limits in determining storage vessel standards applicability. States that use permit-by-rule or general permits have the discretion to evaluate at any time (including now or as they develop their state plans to implement EG OOOOc) whether to modify those rules to incorporate the new criteria for legally and practicably enforceable limitations.

The EPA notes that for both new and existing sources, it is a voluntary decision on the part of an owner or operator to obtain a permit with “legally and practicably enforceable” criteria in order to avoid having to comply with the applicable standard in NSPS OOOOb or a state or Federal plan pursuant to EG OOOOc. A source may opt to comply with the underlying rule when the potential for VOC or methane emissions exceeds the relevant applicability thresholds. In the future, the EPA may initiate further rulemaking to address this provision if its implementation merits further regulatory action.

The EPA disagrees that the criteria the EPA is promulgating conflict with other CAA programs, such as title V and NSR programs. The EPA cannot understand how more specific criteria for a specific purpose within NSPS OOOOb can undermine compliance with title V and NSR permits, and the commenter did not provide specific examples that the EPA could review. Further, while the LPE criteria being finalized here may be more stringent than what states are currently using for other contexts, the commenter has not identified any direct conflict that would prevent the commenter from meeting the criteria in other programs, as more stringent criteria can be used to demonstrate compliance with less stringent requirements.

In response to the comment that approved SIP rules are federally enforceable, the EPA agrees. The EPA's promulgation of NSPS OOOOb and EG OOOOc does not affect previously approved SIP actions that incorporate NSPS OOOO or OOOOa. The EPA is establishing requirements for sources subject to NSPS OOOOb and EG OOOOc to show ongoing compliance with the NSPS, and if the revised NSPS subparts are adopted and approved as part of a SIP, the LPE criteria provisions will be federally enforceable for permits issued within the state. The EPA routinely revises such standards to address the next generation of sources. In this instance EPA is adding a pollutant and further defining how legally and practicably enforceable limits must be supported by site-specific information that supports an operator's claim to be operating within those limits, in compliance with the rule.

As the commenters note, in 2013, the EPA found that 11 states already required control devices for storage vessels, including both Texas and New Mexico, such that the EPA could subtract the storage vessels in these states “from the overall count of storage vessels that would be subject to the final rule.” However, the purpose of referring to those state regulations was in order to estimate the total number of storage vessels that would need to be controlled nationwide and evaluate whether there were enough control devices available to owners and operators of storage vessels for implementation of the rule in the process of considering a petition for reconsideration. The EPA disagrees with the commenter's assertion that the EPA made a “determination” as to the adequacy of the state permitting regulations for purposes of determining applicability of the NSPS. In particular, the EPA did not make any determination as to the legal and practicable enforceability of the state permitting regulations, including for Texas or New Mexico.

Regarding the concern that existing sources do not have methane limits in permits now, CAA section 111(d) and the EPA's implementing regulations in 40 CFR part 60, subpart Ba, mandate that states adopt plans to set performance standards for designated pollutants; for purposes of EG OOOOc, the designated pollutant is GHGs, and the presumptive standards in EG OOOOc are expressed in the form of methane. Therefore, only permit limits on methane emissions can be included in determining applicability of the methane standards for storage vessels in the applicable state or Federal plan implementing EG OOOOc. The EPA agrees with the commenter that a reasonable period of time may be required to adopt state plans consistent with EG OOOOc, including to revise permit limits for storage vessels that choose to be subject to a legally and practicably enforceable limit below the methane applicability threshold. For that reason, as discussed in section XIII.E.2, the EPA has allowed states 24 months to carry out state rulemaking activity to adopt the appropriate standards. In addition to the 24 months, the EPA requires that states establish compliance deadlines that require compliance with the final state plan within 36 months following the state plan submittal deadline, providing up to 5 years for existing sources to adapt their systems to new Federal and state standards before compliance would be required. Further, because permits for existing sources will need to be reopened to include the final state plan criteria implementing the EG, the EPA does not believe that there is a substantial additional burden in ensuring that the “legally and practicably enforceable” criteria are met.

Commenters are correct that, consistent with the finalization of the “legally and practicably enforceable” criteria, the EPA may determine that some permit limits do not meet the criteria and the tank battery cannot use those limits when determining the potential for VOC and methane emissions; however, the EPA always has the authority to independently assess claims of nonapplicability. Regarding friction with states, as stated previously, the EPA believes finalizing the criteria will provide states with the needed level of specificity and certainty to issue permits that meet the “legally and practicably enforceable” criteria.

c. LPE Criteria

Comment: Several commenters were concerned with the specific criteria provided for LPE. One commenter stated that permits have proposed annual or rolling 12-month limits on emissions and production because the tank PTE thresholds and NSR permitting thresholds are based on annual emissions. The commenter believed that the EPA should clarify that such annual limits meet the proposed 30-day averaging time for production limits especially since facilities are typically permitted for a worst-case scenario. Another criterion likely not in existing permits is “ periodic reporting that demonstrates continuous compliance, ” according to the commenter. Historically, the commenter pointed out, periodic reporting has applied to major sources under title V and affected facilities regulated under a NSPS or NESHAP, which the commenter stated is a small fraction of the sites that will be regulated under NSPS OOOOb and EG OOOOc.

Another commenter stated that the requirements for legally and practicably limiting the “potential for methane emissions” are unclear and conflict with the definition of “potential to emit.” Specifically, the commenter stated:

• It is unclear why the EPA has proposed that production limits must be accompanied by operational limits in order to be legally and practicably enforceable. 40 CFR 60.5386c(e)(2)(i)(A).
• It is unclear how a source would establish parametric limits for production and/or operational limits. 40 CFR 60.5386c(e)(2)(i)(C).
• It is unclear how a source would use a control device to meet an operational limit. 40 CFR 60.5386c(e)(2)(i)(C).

The same commenter stated that the EPA should refer to the available caselaw and guidance on limiting “potential to emit” to ensure that the use of terms such as “production limit,” “operational limit,” and “parametric limit” in the proposed rules are consistent with the widely accepted use of those terms in air permitting programs. One commenter expressed concern that proposed 40 CFR 60.5365b(e)(2)(i)(A), which requires a “quantitative production limit and quantitative operational limit(s) for the equipment, or quantitative operational limits for the equipment,” is inconsistent with longstanding EPA policy. The commenter believed that production and/or operational factors can be used as part of a parametric calculation of emissions, but they need not be standalone. Next, the commenter stated that proposed 40 CFR 60.5365b(e)(2)(i)(B) requires an averaging period of less than 30 days when a production-based limit is used, but the commenter believed that is arbitrary and capricious, as well as inconsistent with EPA policy where the overall standard that the limit is intended to enforce is a tpy ( i.e., annual) standard. In such a case, as here, a 12-month rolling limit, as long as it is well-defined in how it is calculated, is more than adequate, according to the commenter. Finally, the commenter stated that it takes issue with proposed 40 CFR 60.5365b(e)(2)(i)(C) which requires that “where a control device is used to achieve an operational limit, an initial compliance demonstration ( i.e., performance test) for the control device [ ] establishes the parametric limits.” While the commenter agreed that the regulations should certainly allow the use of a compliance demonstration, presumably in the form of a test, there is no reason for the EPA to preclude other means of estimating the control device efficiency, such as AP–42 factors or vendor-provided factors, especially when these factors are known to be conservative.

Response: With respect to the proposed 30-days-or-less averaging time period for a production-based limit, the EPA agrees that a rolling 12-month average is an acceptable alternative to a month-by-month determination, where the rolling 12-month average is supported by 30-day subtotals, beginning in the first 30 days, and redetermined every month. This is consistent with the EPA's longstanding guidance, which expresses the Agency's “preference toward short term limits, generally daily but not to exceed a month.” The 30-day averaging time is particularly needed here because determination of potential emissions (and in turn storage vessel standards applicability) is required within the first 30 days after startup of production for tank batteries at well sites and centralized production facilities; an averaging period longer than 30 days would mean there will not be sufficient data to estimate potential emissions by the 30-day deadline whether the production limit effectively caps a tank battery's potential emissions below the applicable threshold(s) under NSPS OOOOb or EG OOOOc. Therefore, when establishing permit limits on production or operation, the EPA believes that such limits should not exceed 30 days. The EPA also points out that a violation of a 12-month standard without any prior interval to verify compliance has the potential to create a full year of noncompliance and associated penalties for failure to demonstrate ongoing compliance.

Regarding production limits and operational limits, the final rule provides that if a production limit is used, it must be accompanied by operational limits to be legally and practicably enforceable because in that situation, potential VOC and methane emissions from a storage vessel are a function of both the facility's operational conditions and production rates. Therefore, both are inputs to the storage vessel emissions calculations. Also, because changes in either may result in an increase in vessel emissions, monitoring is required for both the operational conditions and the production rates used to establish emissions from the storage vessel.

The EPA does not believe, and the commenter did not explain how, the usage of “production limit,” “operational limit,” and “parametric limit” in the proposed rules is inconsistent with the widely accepted use of those terms in air permitting programs. The EPA clarifies that an operational limit on a control device is typically the claimed reduction efficiency of the control system, such as the destruction efficiency of a flare or availability of the VRU to route vapors to process. To demonstrate compliance with such operational limits, parametric limits for a control device are established during manufacturer or source-specific performance testing of the device. The EPA clarifies that “parametric limits” refer to limits on a parameter that can act as a reliable indicator of an emissions-producing (or emissions-reducing) activity or process. Parametric limits for control devices can include flow rate, inlet pressure, residence time, combustion zone temperature, or similar metrics.

Regarding the comment on the use of AP–42 and vendor-provided emission factors for estimating control efficiency of control devices, the EPA clarifies that the proposed LPE criteria do not preclude such use of emission factors. Rather, the criteria require an initial compliance demonstration ( i.e., performance testing) for a control device to establish parametric limits where a control device is used to achieve an operational limit. It is not clear, and the commenter did not explain how, AP–42 or vendor-provided emission factors could be used to establish parametric limits. The EPA is therefore finalizing the LPE criteria as proposed.

2. Modification

Comment: Several commenters expressed concern that the EPA has departed from the definition of modification found at 40 CFR 60.14. One commenter recommended that the EPA limit modifications to where the operator increases emissions from the tank battery by increasing the capacity of the tank battery. The commenter explained that as proposed, subparagraphs (A) and (B)of 60 CFR 60.5365b(e)(3)(ii) would trigger a potential modification even where the increase in capacity of the tank battery is not accompanied by an increase in the tank battery's emissions rate. The commenter stated that operators may readily track and document the addition or replacement of storage vessels within a tank battery. The commenter cautioned that if the EPA does not define modification to require an increase in the emissions rate of the tank battery, perverse outcomes may occur. By way of example, the commenter explained that an operator may increase the size of tank battery without increasing the emissions from the tank battery, and if the emissions (which have not changed) exceed the applicability threshold, the tank battery would become an affected facility. The commenter explained that this possibility is real given that the EPA now proposes to apply the 6 tpy VOC and 20 tpy methane applicability thresholds to the entire tank battery, where it previously under NSPS OOOO and NSPS OOOOa used the same VOC threshold but on an individual storage vessel basis, which effectively reduces the NSPS applicability threshold proportionally by the number of individual storage vessels in a tank battery.

Regarding subparagraphs (C) and (D) of 40 CFR 60.5365b(e)(3)(ii), the same commenter explained that per 40 CFR 60.14(e)(2), an increase in throughput for a storage vessel, accomplished without a capital expenditure on that storage vessel, is not considered a modification and the EPA has not fully explained why it is proposing to deviate from the historical legal understanding of modification which requires both an increase in throughput and a capital expenditure on the storage vessel or tank battery. Other commenters expressed similar concerns regarding capital expenditure. Two commenters noted that increases in liquid throughput at well sites, central production facilities, and compressor stations are difficult to track, as operators typically track liquid throughput using tank gauging rather than flow meters. Further, one commenter explained, the modification criteria for tank batteries at well sites and centralized production sites serve as a disincentive to the centralization of facilities, as the addition of production from a new well to an existing centralized production facility would trigger a modification under 40 CFR 60.5395b(e)(3)(ii)(C). The commenter urged the EPA to consider that if the EPA does not remove the criteria at 40 CFR 60.5395b(e)(3)(ii)(C), the increase in liquid throughput also must be accompanied by a capital expenditure on the tank battery itself. The commenter explained that some actions, such as drilling a new well or fracturing or refracturing an existing well, could increase liquid throughput and require capital expenditure but not necessarily on the tank battery itself.

The same commenter recommended other clarifications to subparagraph 40 CFR 60.5395b(e)(3)(ii)(C). First, the commenter believed that the EPA should remove the reference to “process unit” in subparagraph (C), because “process unit” is defined in the rule within the context of facilities that process natural gas, not well sites and centralized production facilities, and that the reference to process unit in the context of well sites and centralized production facilities is confusing and misplaced. Second, the commenter stated that the EPA should limit the scope of subparagraph (C) to “actions taken with respect to equipment that directly, or through a series of equipment, provides crude oil, condensate, intermediate hydrocarbons, or produced water throughput to the tank battery, including the addition of, or change to, a production well (including hydraulic fracturing or refracturing of the well).” By way of example, the commenter explained that hydraulic fracturing activities occurring in the vicinity of a well that delivers produced liquids to a storage tank battery may temporarily increase production of the well, which would, in turn, increase throughput of the tank battery, but as drafted, it is unclear whether this increase in production is an “action” that modified the tank battery if it resulted in exceedance of the potential for emissions threshold. The commenter believed the increase in production should not be considered an action, as operators cannot plan for or anticipate increases in production from activities occurring offsite that are outside the scope of operations associated with the tank battery. Further, in this example, the commenter explained that the cause of a temporary increase in production may be unknown to the operator and considering “actions” having no direct relationship to equipment in the definition of modification would be a far and extreme departure from longstanding NSPS modification principles. If the EPA retains these modification triggers, the commenter requested that well sites and centralized production facilities also be allowed to compare liquid throughputs to limits in a legally and practicably enforceable permit as is allowed for compressor stations and natural gas processing plants. The commenter believed this recommendation would also make modification criteria consistent for all sites and clearly define what an increase in liquid throughput is.

Similarly, one commenter stated that the December 2022 Supplemental Proposal is not only inconsistent with the statutory definition of “modification” but also inconsistent with the EPA's prior interpretation that a “modification” requires some physical change to a tank. See Letter from Valdus Adamkus, EPA Region 5, to Bradley Miller, Hamilton County Environmental Services (March 25, 1996) (increase in vapor pressure resulting in increased tank emissions was not a “modification” under 40 CFR part 60, subpart Kb because there were no physical changes to the tank). The commenter was concerned that, unless the proposed definition of “modification” is revised to require a physical change or change in the method of operations, midstream owners and operators could find their equipment “modified” solely based on the decisions of upstream third parties and without taking any action themselves.

Another commenter provided some specific recommendations, if the EPA decides to include increases in liquid throughput as a criterion for modification:

• The increase in liquid throughput must also be accompanied by a capital expenditure on the tank battery itself. Actions, such as drilling a new well or fracturing or refracturing an existing well, could increase liquid throughput and require capital expenditure but not necessarily on the tank battery itself. These actions would not be considered modifications to the tank battery unless there is capital expenditure on the tank battery itself. This recommendation would make NSPS OOOOb consistent with the general provisions in 40 CFR 60 subpart A.

• Reference to process unit in 40 CFR 60.5365(e)(ii)(C) should be removed since process unit is defined such that they should not exist at well sites and centralized production facilities. Process unit is a term specific to natural gas processing plants and does not apply to well sites and centralized production facilities.

• Well sites and centralized production facilities should also be allowed to compare liquid throughputs to limits in a legally and practicably enforceable permit like compressor stations and natural gas processing plants. The EPA should be consistent and allow well sites and centralized production facilities to compare liquid throughputs to limits in a legally and practicably enforceable permit since such a permit can be relied upon for the PTE determination for all sites.

• In the absence of a legally and practicably enforceable limit, all sites should be allowed to compare liquid throughputs to those used to design the existing cover and closed vent system in operation when a potential modification action occurs. These recommendations would also make modification criteria consistent for all sites and clearly define what an increase in liquid throughput is.

The same commenter offered suggested edits to 40 CFR 60.5365b(e)(3)(ii) consistent with their recommendations.

Response: The EPA is finalizing the provisions regarding modification as proposed, except for minor edits to the regulatory text at 40 CFR 60.5365b(e)(3)(ii) to replace “result in” with “occurs” such that the provision is as follows: “ `Modification' of a tank battery occurs when any of the actions in paragraphs (e)(3)(ii)(A) through (D) of this section occur and the potential for VOC or methane emissions meets or exceeds either of the thresholds specified in paragraphs (e)(1)(i) or (ii) of this section.” The EPA is making this change because the EPA already has determined that the actions described in 40 CFR 60.5365b(e)(3)(ii)(A) through (D) result in an emissions increase, and the term “result in” may be incorrectly interpreted to suggest otherwise.

CAA section 111(a)(4) defines “modification” as “any physical change or operational change in a stationary source which increases the amount of any air pollutant emitted by such source . . . .” While the general provisions at 40 CFR 60.14 provide a definition of modification, 40 CFR 60.14(f) specifically authorizes the EPA to provide subpart-specific definition for “modification” that would supersede any conflicting provision in 40 CFR 60.14. Pursuant to its authority under 40 CFR 60.14(f), the EPA proposed to define “modification” of a tank battery under NSPS OOOOb (40 CFR 60.5365b(e)(3)(ii)) to mean when the potential emissions of the tank battery exceed the 6 tpy VOC or 20 tpy methane threshold following any of the following physical or operational changes:

(A) a storage vessel is added to an existing tank battery;

(B) one or more storage vessels are replaced such that the cumulative storage capacity of the existing tank battery increases;

(C) for tank batteries at well sites or centralized production facilities, an existing tank battery receives additional crude oil, condensate, intermediate hydrocarbons, or produced water throughput from actions, including but not limited to, the addition of operations or a production well, or changes to operations or a production well (including hydraulic fracturing or refracturing of the well); or

(D) for tank batteries at compressor stations or onshore natural gas processing plants, an existing tank battery receives additional fluids which cumulatively exceed the throughput used in the most recent ( i.e., prior to an action in paragraphs (e)(3)(ii)(A), (B) or (D) of this section) determination of the potential for VOC or methane emissions.

The EPA did not propose to require a showing of an emission increase, having determined that each of the four scenarios describes a physical or operational change that results in an emission increase. With respect to scenarios (A) and (B) above, the EPA explained in the November 2021 Proposal that even if the type and quantity of fluid processed remain the same, the increased storage capacity will lead to higher breathing losses and thereby increase emissions from the tank battery. See 86 FR 63198. With respect to scenario (C), as the EPA explained in the November 2021 Proposal (86 FR 63199) and reiterated in the December 2022 Supplemental Proposal (87 FR 74802), “actions occurring at a well site, such as refracturing a well or adding a new well that sends these liquids to the tank battery at the well site or centralized production facility, would result in an increase in VOC and methane emissions based on an increase in volumetric throughput to the tank battery.” With respect to scenario (D), which addresses storage vessels at compressor stations and gas processing plants, the EPA acknowledges that “storage vessels at these locations are designed to receive liquids from multiple well sites that may startup production over a longer period of time”; the EPA therefore “agrees that when a tank battery at a compressor station or onshore natural gas processing plant receives additional throughput which has already been accounted for in the design capacity of that tank battery and included as a legally and practically enforceable limit in a permit for the tank battery, that additional throughput does not result in an emission increase from the tank battery because those emissions have already been accounted for in the permit.” (87 FR 74802). In other words, there is emission increase under scenario (D) when the emissions from the additional throughput is not accounted for in the design capacity of the tank battery.

While the EPA has determined that an emissions increase results from each of the four scenarios described in 40 CFR 60.5365b(e)(3)(ii), none of them automatically result in the potential for VOC or methane emissions to be at or above the VOC or methane emissions thresholds in NSPS OOOOb; each of the scenarios would trigger the need to complete the “potential for VOC or methane emissions” determination under 40 CFR 60.5365b(e)(1)(ii).

The EPA disagrees with the comment that modification based on an increase in the tank battery's capacity ( i.e., scenarios (A) and (B)) must be accompanied by an increase in the tank battery's emission rate and that modification based on increased throughput ( i.e., scenarios (C) and (D)) must be accompanied by a capital expenditure. As mentioned above, CAA section 111(a)(4) defines “modification” as “any physical change or operational change in a stationary source which increases the amount of any air pollutant emitted by such source . . . .” The statutory definition does not require that there be an increase in an “emission rate,” and it makes no reference to “capital expenditure”; therefore, neither is requisite to determining modification. Further, 40 CFR 60.14(f) authorizes the EPA to set forth “[s]pecial provisions . . . under an applicable subpart of this part [that] shall supersede any conflicting provisions of this section.”