ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2021-0317; FRL-8510-02-OAR]

RIN 2060-AV16

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: Proposed rule.

SUMMARY: This document comprises three distinct groups of actions under the Clean Air Act (CAA) which are collectively intended to significantly reduce emissions of greenhouse gases (GHGs) and other harmful air pollutants from the Crude Oil and Natural Gas source category. First, the EPA proposes to revise the new source performance standards (NSPS) for GHGs and volatile organic compounds (VOCs) for the Crude Oil and Natural Gas source category under the CAA to reflect the Agency's most recent review of the feasibility and cost of reducing emissions from these sources. Second, the EPA proposes emissions guidelines (EG) under the CAA, for states to follow in developing, submitting, and implementing state plans to establish performance standards to limit GHGs from existing sources (designated facilities) in the Crude Oil and Natural Gas source category. Third, the EPA is taking 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,” Sept. 14, 2020 (“2020 Policy Rule”). This proposal responds to the President's January 20, 2021, Executive order (E.O.) titled “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis,” which directed the EPA to consider taking the actions proposed here.

DATES:Comments. Comments must be received on or before January 14, 2022. Under the Paperwork Reduction Act (PRA), comments on the information collection provisions are best assured of consideration if the Office of Management and Budget (OMB) receives a copy of your comments on or before December 15, 2021.

Public hearing: The EPA will hold a virtual public hearing on November 30, 2021 and December 1, 2021. See SUPPLEMENTARY INFORMATION for information on the hearing.

ADDRESSES: You may send comments, identified by Docket ID No. EPA-HQ-OAR-2021-0317 by any of the following methods:

• Federal eRulemaking Portal: https://www.regulations.gov/ (our preferred method). Follow the online instructions for submitting comments.

• Email: a-and-r-docket@epa.gov. Include Docket ID No. EPA-HQ-OAR-2021-0317 in the subject line of the message.

• Fax: (202) 566-9744. Attention Docket ID No. EPA-HQ-OAR-2021-0317.

• Mail: U.S. Environmental Protection Agency, EPA Docket Center, Docket ID No. EPA-HQ-OAR-2021-0317, Mail Code 28221T, 1200 Pennsylvania Avenue NW, Washington, DC 20460.

• Hand/Courier Delivery: EPA Docket Center, WJC West Building, Room 3334, 1301 Constitution Avenue NW, Washington, DC 20004. The Docket Center's hours of operation are 8:30 a.m.-4:30 p.m., Monday-Friday (except Federal holidays).

Instructions: All submissions received must include the Docket ID No. for this rulemaking. Comments received may be posted without change to https://www.regulations.gov/, including any personal information provided. For detailed instructions on sending comments and additional information on the rulemaking process, see the “Public Participation” heading of the SUPPLEMENTARY INFORMATION section of this document. Out of an abundance of caution for members of the public and our staff, the EPA Docket Center and Reading Room are closed to the public, with limited exceptions, to reduce the risk of transmitting COVID-19. Our Docket Center staff will continue to provide remote customer service via email, phone, and webform. We encourage the public to submit comments via https://www.regulations.gov/ or email, as there may be a delay in processing mail and faxes. Hand deliveries and couriers may be received by scheduled appointment only. For further information on EPA Docket Center services and the current status, please visit us online at https://www.epa.gov/dockets.

FOR FURTHER INFORMATION CONTACT: For questions about this proposed action, contact Ms. Karen Marsh, Sector Policies and Programs Division (E143-05), Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency, Research Triangle Park, North Carolina 27711; telephone number: (919) 541-1065; fax number: (919) 541-0516; and email address: marsh.karen@epa.gov or Ms. Amy Hambrick, Sector Policies and Programs Division (E143-05), Office of Air Quality Planning and Standards, Environmental Protection Agency, Research Triangle Park, North Carolina 27711, telephone number: (919) 541-0964; facsimile number: (919) 541-3470; email address: hambrick.amy@epa.gov.

SUPPLEMENTARY INFORMATION:

Participation in virtual public hearing. Please note that the EPA is deviating from its typical approach for public hearings, because the President has declared a national emergency. Due to the current Centers for Disease Control and Prevention (CDC) recommendations, as well as state and local orders for social distancing to limit the spread of COVID-19, the EPA cannot hold in-person public meetings at this time.

The public hearing will be held via virtual platform on November 30, 2021, and December 1, 2021, and will convene at 11:00 a.m. Eastern Time (ET) and conclude at 9:00 p.m. ET each day. On each hearing day, the EPA may close a session 15 minutes after the last pre-registered speaker has testified if there are no additional speakers. The EPA will announce further details at https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry. If the EPA receives a high volume of registrations for the public hearing, we may continue the public hearing on December 2, 2021. The EPA does not intend to publish a document in the Federal Register announcing the potential addition of a third day for the public hearing or any other updates to the information on the hearing described in this document. Please monitor https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry for any updates to the information described in this document, including information about the public hearing. For information or questions about the public hearing, please contact the public hearing team at (888) 372-8699 or by email at SPPDpublichearing@epa.gov.

The EPA will begin pre-registering speakers for the hearing upon publication of this document in the Federal Register . The EPA will accept registrations on an individual basis. To register to speak at the virtual hearing, follow the directions at https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry or contact the public hearing team at (888) 372- 8699 or by email at SPPDpublichearing@epa.gov. The last day to pre-register to speak at the hearing will be November 24, 2021. Prior to the hearing, the EPA will post a general agenda that will list pre-registered speakers in approximate order at: https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry.

The EPA will make every effort to follow the schedule as closely as possible on the day of the hearing; however, please plan for the hearings to run either ahead of schedule or behind schedule.

Each commenter will have 5 minutes to provide oral testimony. The EPA encourages commenters to provide the EPA with a copy of their oral testimony electronically (via email) by emailing it to marsh.karen@epa.gov and hambrick.amy@epa.gov. The EPA also recommends submitting the text of your oral testimony as written comments to the rulemaking docket.

The EPA may ask clarifying questions during the oral presentations but will not respond to the presentations at that time. Written statements and supporting information submitted during the comment period will be considered with the same weight as oral testimony and supporting information presented at the public hearing.

If you require the services of an interpreter or a special accommodation such as audio description, please pre-register for the hearing with the public hearing team and describe your needs by November 22, 2021. The EPA may not be able to arrange accommodations without advanced notice.

Docket. 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 in https://www.regulations.gov/. 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. With the exception of such material, publicly available docket materials are available electronically in https://www.regulations.gov/.

Instructions. Direct your comments to Docket ID No. EPA-HQ-OAR-2021-0317. The EPA's policy is that all comments received will be included in the public docket without change and may be made available online at https://www.regulations.gov/, including any personal information provided, unless the comment includes information claimed to be CBI or other information whose disclosure is restricted by statute. Do not submit information that you consider to be CBI or otherwise protected through https://www.regulations.gov/ or email. This type of information should be submitted by mail as discussed below.

The EPA may publish any comment received to its public docket. Multimedia submissions (audio, video, etc.) must be accompanied by a written comment. The written comment is considered the official comment and should include discussion of all points you wish to make. The EPA will generally not consider comments or comment contents located outside of the primary submission ( i.e., on the Web, cloud, or other file sharing system). For additional submission methods, the full EPA public comment policy, information about CBI or multimedia submissions, and general guidance on making effective comments, please visit https://www.epa.gov/dockets/commenting-epa-dockets.

The https://www.regulations.gov/ website allows you to submit your comment anonymously, which means the EPA will not know your identity or contact information unless you provide it in the body of your comment. If you send an email comment directly to the EPA without going through https://www.regulations.gov/, your email address will be automatically captured and included as part of the comment that is placed in the public docket and made available on the internet. If you submit an electronic comment, the EPA recommends that you include your name and other contact information in the body of your comment and with any digital storage media you submit. If the EPA cannot read your comment due to technical difficulties and cannot contact you for clarification, the EPA may not be able to consider your comment. Electronic files should not include special characters or any form of encryption and be free of any defects or viruses. For additional information about the EPA's public docket, visit the EPA Docket Center homepage at https://www.epa.gov/dockets.

The EPA is temporarily suspending its Docket Center and Reading Room for public visitors, with limited exceptions, to reduce the risk of transmitting COVID-19. Our Docket Center staff will continue to provide remote customer service via email, phone, and webform. We encourage the public to submit comments via https://www.regulations.gov/ as there may be a delay in processing mail and faxes. Hand deliveries or couriers will be received by scheduled appointment only. For further information and updates on EPA Docket Center services, please visit us online at https://www.epa.gov/dockets.

The EPA continues to carefully and continuously monitor information from the CDC, local area health departments, and our Federal partners so that we can respond rapidly as conditions change regarding COVID-19.

Submitting CBI. Do not submit information containing CBI to the EPA through https://www.regulations.gov/ or email. Clearly mark the part or all of the information that you claim to be CBI. For CBI information on any digital storage media that you mail to the EPA, mark the outside of the digital storage media as CBI and then identify electronically within the digital storage media the specific information that is claimed as CBI. In addition to one complete version of the comments that includes information claimed as CBI, you must submit a copy of the comments that does not contain the information claimed as CBI directly to the public docket through the procedures outlined in Instructions above. If you submit any digital storage media that does not contain CBI, mark the outside of the digital storage media clearly that it does not contain CBI. Information not marked as CBI will be included in the public docket and the EPA's electronic public docket without prior notice. Information marked as CBI will not be disclosed except in accordance with procedures set forth in 40 CFR part 2. Send or deliver information identified as CBI only to the following address: OAQPS Document Control Officer (C404-02), OAQPS, U.S. Environmental Protection Agency, Research Triangle Park, North Carolina 27711, Attention Docket ID No. EPA-HQ-OAR-2021-0317. Note that written comments containing CBI submitted by mail may be delayed and no hand deliveries will be accepted.

Preamble acronyms and abbreviations. 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:

ACE Affordable Clean Energy rule

AEO Annual Energy Outlook

AMEL alternate means of emissions limitation

ANGA American Natural Gas Alliance

ANSI American National Standards Institute

APCD air pollution control devices

API American Petroleum Institute

ARPA-E Advanced Research Projects Agency-Energy

ASME American Society of Mechanical Engineers

ASTM American Society for Testing and Materials

AVO audio, visual, olfactory

BACT best achievable control technology

BOEM Bureau of Ocean Energy Management

BLM Bureau of Land Management

BMP best management practices

boe barrels of oil equivalents

BSER best system of emission reduction

BTEX benzene, toluene, ethylbenzene, and xylenes

CAA Clean Air Act

CBI Confidential Business Information

CDC Center for Disease Control

CDX EPA's Central Data Exchange

CEDRI Compliance and Emissions Data Reporting Interface

CFR Code of Federal Regulations

CH ₄  methane

cm centimeter

CPI consumer price index

CPI-U consumer price index urban

CO carbon monoxide

COPD chronic obstructive pulmonary disease

CO ₂  carbon dioxide

CO ₂ Eq. carbon dioxide equivalent

COA condition of approval

COS carbonyl sulfide

CRA Congressional Review Act

CS ₂  carbon disulfide

CVS closed vent systems

DC direct current

DOE Department of Energy

DOI Department of the Interior

DOT Department of Transportation

EAV equivalent annualized value

EDF Environmental Defense Fund

EG emission guidelines

ECOS Environmental Council of the States

EGU electricity generating units

EIA U.S. Energy Information Administration

EJ environmental justice

EO Executive Order

EPA Environmental Protection Agency

ERT Electronic Reporting Tool

FERC The U.S. Federal Energy Regulatory Commission

fpm feet per minute

GC gas chromatograph

GHGs greenhouse gases

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

GHGRP Greenhouse Gas Reporting Program

GRI Gas Research Institute

GWP global warning potential

HAP hazardous air pollutant(s)

HC hydrocarbons

HFC hydrofluorocarbons

H ₂ S hydrogen sulfide

ICR Information Collection Request

IOGCC Interstate Oil and Gas Compact Commission

IPCC Intergovernmental Panel on Climate Change

IR infrared

IRFA initial regulatory flexibility analysis

kt kilotons

kg kilograms

low-e low emission

LDAR leak detection and repair

Mcf thousand cubic feet

MMT million metric tons

MRR monitoring, recordkeeping, and reporting

MW megawatt

NAAQS National Ambient Air Quality Standards

NAICS North American Industry Classification System

NCA4 2017-2018 Fourth National Climate Assessment

NEI National Emissions Inventory

NEMS National Energy Modeling System

NESHAP National Emissions Standards for Hazardous Air Pollutants

NGL natural gas liquid

NGO non-governmental organization

NOAA National Oceanic and Atmospheric Administration

NO _X  nitrogen oxides

NSPS new source performance standards

NTTAA National Technology Transfer and Advancement Act

OCSLA The Outer Continental Shelf Lands Act

OAQPS Office of Air Quality Planning and Standards

OIG Office of the Inspector General

OGI optical gas imaging

OMB Office of Management and Budget

PE professional engineer

PFCs perfluorocarbons

PHMSA Pipeline and Hazardous Materials Safety Administration

PM particulate matter

PM _2.5  PM with a diameter of 2.5 micrometers or less

ppb parts per billion

ppm parts per million

PRA Paperwork Reduction Act

PRD pressure release device

PRV pressure release valve

PSD Prevention of Significant Deterioration

psig pounds per square inch gauge

PTE potential to emit

PV present value

REC reduced emissions completion

RFA Regulatory Flexibility Act

RIA Regulatory Impact Analysis

RTC response to comments

SBAR Small Business Advocacy Review

SC-CH ₄  social cost of methane

SCF significant contribution finding

scf standard cubic feet

scfh standard cubic feet per hour

scfm standard cubic feet per minute

SF ₆  sulfur hexafluoride

SIP State Implementation Plan

SO ₂  sulfur dioxide

SO _X  sulfur oxides

tpy tons per year

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

TAR Tribal Authority Rule

TIP Tribal Implementation Plan

TSD technical support document

TTN Technology Transfer Network

UAS unmanned aircraft systems

UIC underground injection control

UMRA Unfunded Mandates Reform Act

U.S. United States

USGCRP U.S. Global Change Research Program

USGS U.S. Geologic Survey

VCS Voluntary Consensus Standards

VOC volatile organic compounds

VRD vapor recovery device

VRU vapor recovery unit

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

I. Executive Summary

A. Purpose of the Regulatory Action

B. Summary of the Major Provisions of This Regulatory Action

C. Costs and Benefits

II. General Information

A. Does this action apply to me?

B. How do I obtain a copy of this document, background information, other related information?

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

A. Impacts of GHGs, VOC and SO ₂ Emissions on Public Health and Welfare

B. 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. Effect of the CRA

V. Related Emissions Reduction Efforts

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

B. Industry and Voluntary Actions To Address Climate Change

VI. Environmental Justice Considerations, Implications, and Stakeholder Outreach

A. Environmental Justice and the Impacts of Climate Change

B. Impacted Stakeholders

C. Outreach and Engagement

D. Environmental Justice Considerations

VII. Other Stakeholder Outreach

A. Educating the Public, Listening Sessions, and Stakeholder Outreach

B. EPA Methane Detection Technology Workshop

C. How is this information being considered in this proposal?

VIII. Legal Basis for Proposal Scope

A. Recent History of the EPA's Regulation of Oil and Gas Sources and Congress's Response

B. Implications of Congress's Disapproval of the 2020 Policy Rule

C. Alternative Conclusion Affirming the Legal Interpretations in the 2016 Rule

D. Impacts on Regulation of Methane Emissions From Existing Sources

IX. 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 EPA evaluate control costs in this action?

X. Summary of Proposed Action for NSPS OOOOa

A. Amendments to Fugitive Emissions Monitoring Frequency

B. Technical and Implementation Amendments

XI. Summary of Proposed NSPS OOOOb and EG OOOOc

A. Fugitive Emissions From Well Sites and Compressor Stations

B. Storage Vessels

C. Pneumatic Controllers

D. Well Liquids Unloading Operations

E. Reciprocating Compressors

F. Centrifugal Compressors

G. Pneumatic Pumps

H. Equipment Leaks at Natural Gas Processing Plants

I. Well Completions

J. Oil Wells With Associated Gas

K. Sweetening Units

L. Centralized Production Facilities

M. Recordkeeping and Reporting

N. Prevention of Significant Deterioration and Title V Permitting

XII. Rationale for Proposed NSPS OOOOb and EG OOOOc

A. Proposed Standards for Fugitive Emissions From Well Sites and Compressor Stations

B. Proposed Standards for Storage Vessels

C. Proposed Standards for Pneumatic Controllers

D. Proposed Standards for Well Liquids Unloading Operations

E. Proposed Standards for Reciprocating Compressors

F. Proposed Standards for Centrifugal Compressors

G. Proposed Standards for Pneumatic Pumps

H. Proposed Standards for Equipment Leaks at Natural Gas Processing Plants

I. Proposed Standards for Well Completions

J. Proposed Standards for Oil Wells With Associated Gas

K. Proposed Standards for Sweetening Units

XIII. Solicitations for Comment on Additional Emission Sources and Definitions

A. Abandoned Wells

B. Pigging Operations and Related Blowdown Activities

C. Tank Truck Loading

D. Control Device Efficiency and Operation

E. Definition of Hydraulic Fracturing

XIV. 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)

XV. Prevention of Significant Deterioration and Title V Permitting

A. Overview

B. Applicability of Tailoring Rule Thresholds Under the PSD Program

C. Implications for Title V Program

XVI. Impacts of This Proposed Rule

A. What are the air impacts?

B. What are the energy impacts?

C. What are the compliance costs?

D. What are the economic and employment impacts?

E. What are the benefits of the proposed standards?

XVII. Statutory and Executive Order Reviews

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

B. Paperwork Reduction Act (PRA)

C. Regulatory Flexibility Act (RFA)

D. Unfunded Mandates Reform Act (UMRA)

E. Executive Order 13132: Federalism

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

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

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

I. National Technology Transfer and Advancement Act (NTTAA)

J. Executive Order 12898: Federal Actions To Address Environmental Justice in Minority Populations and Low-Income Populations

I. Executive Summary

A. Purpose of the Regulatory Action

This proposed 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, ¹ specifically the Crude Oil and Natural Gas source category. ² The Oil and Natural Gas Industry is the United States' largest industrial emitter of methane, a highly potent GHG. Human activity-related emissions of methane 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 (a well-mixed gas is one with an atmospheric lifetime longer than a year or two, which allows the gas to be mixed around the world, meaning that the location of emission of the gas has little importance in terms of its impacts). 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 and are 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 carbon dioxide (CO ₂ ), VOC, sulfur dioxide (SO ₂ ), nitrogen oxide (NO _X ), hydrogen sulfide (H ₂ S), carbon disulfide (CS ₂ ), and carbonyl sulfide (COS), as well as benzene, toluene, ethylbenzene, and xylenes (this group is commonly referred to as “BTEX”), and n-hexane.

¹  The EPA characterizes the Oil and Natural Gas Industry 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.

²  The EPA defines the Crude Oil and Natural Gas source category to mean (1) crude oil production, which includes the well and extends to the point of custody transfer to the crude oil transmission pipeline or any other forms of transportation; and (2) natural gas production, processing, transmission, and storage, which include the well and extend to, but do not include, the local distribution company custody transfer station. For purposes of this proposed rulemaking, for crude oil, the EPA's focus is on operations from the well to the point of custody transfer at a petroleum refinery, while for natural gas, the focus is on all operations from the well to the local distribution company custody transfer station commonly referred to as the “city-gate”.

Under the authority of CAA section 111, this rulemaking proposes 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 the production, processing, transmission and storage segments. For designated facilities, ³ this rulemaking proposes EG containing presumptive standards for GHG in the form of methane limitations. When finalized, States shall utilize 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.

³  The term “designated facility” means “any existing facility which emits a designated pollutant and which would be subject to a standard of performance for that pollutant if the existing facility were an affected facility.” See 40 CFR 60.21a(b).

The EPA is proposing these actions in accordance with its legal obligations and authorities following a review directed by E.O. 13990, “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis,” issued on January 20, 2021. The EPA intends for these proposed actions to address the far-reaching harmful consequences and real economic costs of climate change. 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 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. One ton of methane in the atmosphere has 80 times the warming impact of a ton of CO ₂ , and contributes to the creation of ground-level ozone which is another greenhouse gas. Because methane has a shorter lifetime than CO ₂ , it has a smaller relative impact—although still significantly greater than CO ₂ —when considering longer time periods. One standard metric is the 100-year global warming potential (GWP), which is a measure of the climate impact of emissions of one ton a greenhouse gas over 100 years relative to the impact of the emissions of one ton of CO ₂ . Even over this long timeframe, methane has a 100-year GWP of almost 30. 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 forcer) is at least as large as that due to a year's worth of CO ₂ emissions.”  ⁴ The IPCC estimated that, depending on the reference scenario, collective reductions in these SLCFs (methane, ozone precursors, and 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, which is important in the context of keeping warming to well below 2 °C (3.6 °F). 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. ⁵ In the absence of additional reduction policies, methane emissions are projected to continue rising through at least 2040.

⁴  However, the IPCC AR6 assessment cautioned that “The effects of the SLCFs decay rapidly over the first few decades after pulse emission. Consequently, on time scales longer than about 30 years, the net long-term temperature effects of sectors and regions are dominated by CO ₂ .”

⁵  Naik, V., S. Szopa, B. Adhikary, P. Artaxo, T. Berntsen, W.D. Collins, S. Fuzzi, L. Gallardo, A. Kiendler 41 Scharr, Z. Klimont, H. Liao, N. Unger, P. Zanis, 2021, Short-Lived Climate Forcers. In: Climate Change 42 2021: The Physical Science Basis. Contribution of Working Group I to the Sixth Assessment Report of the 43 Intergovernmental Panel on Climate Change [Masson-Delmotte, V., P. Zhai, A. Pirani, S.L. Connors, C. 44 Péan, S. Berger, N. Caud, Y. Chen, L. Goldfarb, M.I. Gomis, M. Huang, K. Leitzell, E. Lonnoy, J.B.R. 45 Matthews, T.K. Maycock, T. Waterfield, O. Yelekçi, R. Yu and B. Zhou (eds.)]. Cambridge University 46 Press. In Press.

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 comprised 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 as proposed in these actions, would contribute substantially to global efforts to limit temperature rise, aiding efforts to remain well below 2 °C above pre-industrial levels. See preamble section III for further discussion on the Crude Oil and Natural Gas Emissions and Climate Change, including discussion of the GHGs, VOCs, and SO ₂ 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 seat properly at the end of an automated liquid dumping event, inefficient separation of gas and liquid phases occurs 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 pneumatic pumps and 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 this action, the EPA has taken a comprehensive analysis of the available data from emission sources in the Crude Oil and Natural Gas source category and the latest available information on control measures and techniques to identify achievable, cost-effective measures to significantly reduce emissions, consistent with the requirements of section 111 of the CAA. If finalized and implemented, the actions proposed in this rulemaking would 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. The actions proposed in this rulemaking would:

• Update, strengthen, and expand current requirements under CAA section 111(b) for methane and VOC emissions from new, modified, and reconstructed facilities,

• establish new limits for methane, and VOC emissions from new, modified, and reconstructed facilities that are not currently regulated under CAA section 111(b),

• establish the first nationwide EG for States to limit methane pollution from existing designated facilities in the source category under CAA section 111(d), and

• take comment on additional sources of pollution that, with understanding gained from more information, may offer opportunities for emission reductions, which the EPA would present in a supplemental rulemaking proposal under both CAA section 111(b) and (d).

In developing this proposal, the EPA drew on its own prior experience in regulating sources in the Crude Oil and Natural Gas source category under section 111 and other CAA programs; applied lessons learned from States' regulatory efforts, the emission reduction efforts of leading companies, and the EPA's long-standing voluntary emission reduction programs; and reviewed the latest available information about new and developing technologies, as well as, peer-reviewed research from emission measurement campaigns across the U.S. Further, the EPA undertook extensive pre-proposal outreach to the public and to stakeholders, including three full days of public listening sessions, roundtables with State energy and environmental regulators, a two-day workshop on innovative methane detection technologies, and a nonregulatory docket established in May 2021 to receive written comments. Through this outreach, the EPA heard from diverse voices and perspectives including State and local governments, Tribal nations, communities affected by oil and gas pollution, environmental and public health organizations, and representatives of the oil and natural gas industry, all of which provided ideas and information that helped shape and inform this proposal.

The EPA also considered community and environmental justice implications in the development of this proposal 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 proposed rule and to factor these concerns into this proposal. For example, in addition to establishing EG that extend fugitive emission requirements to existing oil and natural gas facilities, the EPA is proposing to expand leak detection programs already in effect for new sources to include known sources of large emission events and proposing to require more frequent monitoring at sites with more emissions. The EPA is also taking comment on innovative mechanisms to ensure compliance and minimize emissions, including the possibility of providing a pathway for communities to detect and report large emitting events that may require follow-up and mitigation by owners and operators. The extensive pollution reduction measures in this proposal, if finalized, would collectively reduce a suite of harmful pollutants and their associated health impacts in communities adjacent to these emission sources. Further, to help ensure that the needs and perspectives of communities with environmental justice concerns are considered as States develop plans to establish and implement standards of performance for existing sources, the EPA is proposing to require that States demonstrate they have undertaken meaningful outreach and engagement with overburdened and underserved communities as part of their State plan submissions under the EPA. A full discussion of the Environmental Justice Considerations, Implications, and Stakeholder Outreach can be found in section VI of the preamble. A full discussion of Other Stakeholder Outreach is found in section VII of the preamble.

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 intends these proposed actions to build upon progress made by certain States and Federal agencies in reducing GHG and VOC emissions. See preamble section V for fuller discussion of Related State Actions and Other Federal Actions Regulating Oil and Natural Gas Sources and Industry and Voluntary Actions to Address Climate Change.

The EPA believes that a broad ensemble of mutually leveraging efforts across all States and all Federal agencies is essential to meaningfully address climate change effectively. 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 proposal. 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 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.

Throughout this action, unless noted otherwise, the EPA is requesting comments on all aspects of the proposal to enable the EPA to develop a final rule that, consistent with our responsibilities under section 111 of the CAA, achieves the greatest possible reductions in methane and VOC emissions while remaining achievable, cost effective, and conducive to technological innovation. As a further step in the rulemaking process and to solicit additional public input, the EPA plans to issue a supplemental proposal and supplemental RIA for the supplemental proposal to provide regulatory text for the proposed NSPS OOOOb and EG OOOOc. In light of certain innovative elements of this proposed rule and the EPA's request for information that would support the regulation of additional sources in the Crude Oil and Natural Gas source category as part of this rulemaking, the EPA is considering including additional provisions in this supplemental proposal and RIA based on information and comment collected in response to this document.

As noted later in this preamble, the supplemental proposal may address, among other issues: (1) Ways to mitigate methane from abandoned wells, (2) measures to reduce emissions from pipeline pigging operations and other pipeline blowdowns, (3) ways to minimize emissions from tank truck loading operations, and (4) ways to strengthen requirements to ensure proper operation and optimal performance of control devices. In addition, and as noted in the solicitations of comment in this document, the supplemental proposal may revisit and refine certain provisions of this proposal in response to information provided by the public. For instance, the EPA is seeking input on multiple aspects of the proposed approach for fugitive emissions monitoring at well sites, including the baseline emission threshold and other criteria (such as the presence of specific types of malfunction-prone equipment) that should be used to determine whether a well site is required to undertake ongoing fugitive emissions monitoring; the methodology for calculating baseline methane emissions and whether it should account for malfunctions or improper operation of controls at storage vessels; and ways to ensure that emissions from wells owned by small businesses are addressed while still recognizing the greater challenges that small businesses with less dedicated staff and resources for environmental compliance may have. The EPA is also seeking input on ways to ensure that captured associated gas is collected for a useful purpose rather than flared, and the feasibility of requiring broader use of zero-emitting technology for pneumatic pumps.

Finally, the EPA is seeking comment and information on alternative measurement technologies, which we are proposing to allow in the rule. We have heard strong interest from various stakeholders on employing new tools for methane identification and quantification, particularly for large emission sources (commonly known as “super-emitters”). Information provided in response to this proposal may be used to evaluate whether a change in BSER from the proposed quarterly OGI monitoring to a monitoring program using alternative measurement technologies is appropriate. Separate from the role of these alternative measurement technologies in a regulatory monitoring program, we are also soliciting comment on ways to structure a pathway for communities to identify large emission events which owners or operators would then be required to investigate, and mechanisms for the collection and public dissemination of this information, for possible further development as part of a supplemental proposal.

This preamble includes comment solicitations/requests on several topics and issues. We have prepared a separate memorandum that presents these comment requests by section and topic as a guide to assist commenters in preparing comments. This memorandum can be obtained from the Docket for this action (see Docket ID No. EPA-HQ-OAR-2021-0317). The title of the memorandum is “Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review—Proposed Rule Summary of Comment Solicitations.”

B. Summary of the Major Provisions of This Regulatory Action

This proposed rulemaking includes three distinct groups of actions under the CAA that are each severable from the other. First, pursuant to CAA 111(b)(1)(B), the EPA has reviewed, and is proposing revisions to, the standards of performance for the Crude Oil and Natural Gas source category published in 2016 and amended in 2020, codified at 40 CFR part 60, 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 proposing to update, strengthen, and expand the current requirements under CAA section 111(b) for methane and VOC emissions from sources that commenced construction, modification, or reconstruction after November 15, 2021. These proposed 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 2016 NSPS OOOOa.

Second, pursuant to CAA 111(d), the EPA is proposing 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 proposed in this rulemaking will be in a new subpart, 40 CFR part 60, subpart OOOOc (EG OOOOc). The EG are designed to inform States in the development, submittal, and implementation of State plans that are required to establish standards of performance for GHGs from their designated facilities in the Crude Oil and Natural Gas source category.

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 (Sept. 14, 2020) (“2020 Policy Rule”). As explained in Section X of this action (Summary of Proposed Action for NSPS OOOOa), the EPA is proposing 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 proposing to rescind provisions of the 2020 Technical Rule that were not supported by the record for that rule, or by our subsequent information and analysis. The regulatory text for these proposed amendments is included in the docket for this rulemaking at Docket ID EPA-HQ-OAR-2021-0317.

In addition, in the final rule for this action, the EPA will update the NSPS OOOO and NSPS OOOOa provisions in the Code of Federal Regulations (CFR) to reflect the Congressional Review Act (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 though the EPA has not yet updated the CFR text to reflect them. ⁶ These updates to the CFR text are also included in the docket for this rulemaking at Docket ID EPA-HQ-OAR-2021-0317 for public awareness, but the EPA is not soliciting comment on them as they merely reflect current law. Under 5 U.S.C. 553(b)(3)(B), notice and comment is not required “when the agency for good cause finds . . . that notice and public procedure thereon are . . . unnecessary . . . ,”  ⁷ and, as just noted, notice and comment is not necessary for these updates. The EPA is waiting to make these updates to the CFR text until the final rule simply 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 (77 FR 49490, August 16, 2012) and 2016 NSPS OOOOa at the same time.

⁶  See Congressional Review Act Resolution to Disapprove EPA's 2020 Oil and Gas Policy Rule Questions and Answers (June 30, 2021) available at https://www.epa.gov/system/files/documents/2021-07/qa_cra_for_2020_oil_and_gas_policy_rule.6.30.2021.pdf.

⁷  5 U.S.C. 553(b)(3)(B) is applicable to rules promulgated under CAA section 111(b), under CAA section 307(d)(1) (flush language at end).

As CAA section 111(a)(1) requires, the standards of performance being proposed in this action 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 non-air quality health and environmental impact and energy requirement) the Administrator determines has been adequately demonstrated.” This action further proposes 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 proposed rulemaking, we evaluated potential control measures available for the affected facilities, 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 rule typically achieve reductions in multiple pollutants at once and secure a multiplicity of climate and public health benefits. For a detailed discussion of the EPA's consideration of this and other BSER statutory elements, please see sections IV and IX of this preamble.

1. Proposed Standards for New, Modified and Reconstructed Sources After November 15, 2021 (Proposed NSPS OOOOb)

As described in sections XI and XII of this preamble, under the authority of CAA section 111(b)(1)(B) the EPA has reviewed the VOC, GHG (in the form of limitations on methane), and SO ₂ standards in the 2016 NSPS OOOOa (as amended in 2020 by the Technical Rule). Based on its review, the EPA is proposing revisions to the standards for certain emissions sources to reflect the updated BSER for those affected sources. Where our analyses show that the BSER for an affected source remains the same, the EPA is proposing to retain the current standard for that affected source. In addition, the EPA is proposing methane and VOC standards for several new sources that are currently unregulated. The proposed NSPS described above would apply to new, modified, and reconstructed emission 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 November 15, 2021, which is the date of publication of the proposed revisions to the NSPS. In particular, this action proposes to retain the 2016 NSPS OOOOa SO ₂ performance standard for sweetening units and the 2016 OOOOa VOC and methane performance standards for well completions and centrifugal compressors; proposes revisions to strengthen the 2016 NSPS OOOOa VOC and methane standards addressing fugitive emissions from well sites and compressor stations, storage vessels, pneumatic controllers, reciprocating compressors, pneumatic pumps, and equipment leaks at natural gas processing plants; and proposes new VOC and methane standards for well liquids unloading operations and intermittent vent pneumatic controllers, and oil wells with associated gas previously not regulated in the 2016 NSPS OOOOa. A summary of the proposed BSER determination and proposed NSPS for new, modified, and reconstructed sources (NSPS OOOOb) is presented in Table 2. See sections XI and XII of this preamble for a complete discussion of BSER determination and proposed NSPS requirements.

This proposal also solicits certain information relevant to the potential identification of additional emissions sources as affected facilities. Specifically, the EPA is evaluating the potential for establishing standards for abandoned and unplugged wells, blowdown emissions associated with pipeline pig launchers and receivers, and tank truck loading operations. While the EPA has assessed these sources based on currently available information, we have determined that we need additional information to evaluate BSER and to propose NSPS for these emissions sources. A full discussion of the solicitation for comment regarding these additional emission sources is found in section XIII of the preamble.

2. Proposed EG for Sources Constructed Prior to November 15, 2021 (Proposed EG OOOOc)

As described in sections XI and XII of this preamble, under the authority of CAA section 111(d), the EPA is proposing 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, transmission, and storage segments (EG OOOOc). 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 sources but instead provides requirements for states in developing their plans. Although State plans bear the obligation to establish standards of performance, under CAA sections 111(a)(1) and 111(d), those standards of performance must reflect the degree of emission limitation achievable through the application of the BSER as determined by the Administrator. As provided in section 111(d), a State may choose to take into account remaining useful life and other factors in applying a standard of performance to a particular source, consistent with the CAA, the EPA's implementing regulations, and the final EG.

In this action, the EPA is proposing 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. Section XIV 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 proposing to translate 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. By doing this, the EPA has formatted the proposed EG such that if a State chooses to adopt these presumptive standards, once finalized, 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 EG serve a function similar to that of a model rule, ⁸ 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 believes that providing these presumptive standards will create a streamlined approach for States in developing plans and 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 EG does not seek to pre-determine the outcomes of any future rulemaking.

⁸  The presumptive standards are not the same as a Federal plan under CAA section 111(d)(2). The EPA has an obligation to promulgate a Federal plan if a state fails to submit a satisfactory plan. In such circumstances, the final EG and presumptive standards would serve as a guide to the development of a Federal plan. See section XIV.F. for information on Federal plans.

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 that Tribe. A summary of the proposed EG for existing sources (EG OOOOc) for the oil and natural gas sector is presented in Table 3. See sections XI and XII of this preamble for a complete discussion of the proposed EG requirements.

As discussed above for the proposed NSPS OOOOb, the EPA is considering including additional sources as affected facilities in a potential future supplemental rulemaking proposal  ⁹ under CAA section 111(b). The EPA is also considering including these additional sources as designated facilities under the EG in OOOOc in a potential future supplemental rulemaking proposal under CAA section 111(d). As with the proposed NSPS OOOOb, the EPA is evaluating the potential for establishing EG applicable to abandoned and unplugged wells, blowdown emissions associated with pipeline pig launchers and receivers, and tank truck loading operations (assuming the EPA establishes NSPS for these emissions points). As described in section XIII of this preamble, the EPA is soliciting information to assist in this effort.

⁹  A supplemental proposal would include an updated RIA.

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

The EPA is also proposing certain 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 proposed rulemaking, the EPA also is proposing to apply 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, pneumatic pumps, closed vent systems, fugitive emissions, alternative means of emission limitation (AMELs), onshore natural gas processing plants, as well as other technical clarifications and corrections. The EPA also is proposing to repeal 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 apply only to VOC standards (not methane standards) from the production and processing segments. A summary of the proposed amendments to the 2016 OOOOa NSPS is presented in section X of this preamble.

Lastly, in the final rule for this action, the EPA will update 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 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 is waiting to make the updates to the CFR text until the final rule simply 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. In accordance with 5 U.S.C. 553(b)(3)(B), the EPA is not soliciting comment on these updates.

C. Costs and Benefits

To satisfy requirements of E.O. 12866, the EPA projected the emissions reductions, costs, and benefits that may result from this proposed action. These results are presented in detail in the regulatory impact analysis (RIA) accompanying this proposal developed in response to E.O. 12866. The RIA focuses on the elements of the proposed rule that are likely to result in quantifiable cost or emissions changes compared to a baseline without the proposal that incorporates changes to regulatory requirements induced by the CRA resolution. We estimated the cost, emissions, and benefit impacts for the 2023 to 2035 period. We present the present value (PV) and equivalent annual value (EAV) of costs, benefits, and net benefits of this action in 2019 dollars.

The initial analysis year in the RIA is 2023 as we assume the proposed rule will be finalized towards the end of 2022. The NSPS will take effect immediately and impact sources constructed after publication of the proposed rule. The EG will take longer to go into effect as States will need to develop implementation plans in response to the rule and have them approved by the EPA. We assume in the RIA that this process will take three years, and so EG impacts will begin in 2026. The final analysis year is 2035, which allows us to provide ten 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 proposed rule. The EPA estimated the global social benefits of CH ₄ emission reductions expected from this proposed rule using the SC-CH ₄ estimates presented in the “Technical Support Document: Social Cost of Carbon, Methane, and Nitrous Oxide Interim Estimates under E.O. 13990 (IWG 2021)”. These SC-CH ₄ estimates are interim values developed under E.O. 13990 for use in benefit-cost analyses until updated estimates of the impacts of climate change can be developed based on the best available science and economics.

Under the proposed rule, the EPA expects that VOC emission reductions will improve air quality and are likely to improve health and welfare associated with exposure to ozone, PM _2.5 , and HAP. Calculating ozone impacts from VOC emissions changes requires information about the spatial patterns in those emissions changes. In addition, the ozone health effects from the proposed rule will depend on the relative proximity of expected VOC and ozone changes to population. In this analysis, we have not characterized VOC emissions changes at a finer spatial resolution than the national total. In light of these uncertainties, we present an illustrative screening analysis in Appendix B of the RIA based on modeled oil and natural gas VOC contributions to ozone concentrations as they occurred in 2017 and do not include the results of this analysis in the estimate of benefits and net benefits projected from this proposal.

The projected national-level emissions reductions over the 2023 to 2035 period anticipated under the proposed requirements are presented in Table 4. Table 5 presents the PV and EAV of the projected benefits, costs, and net benefits over the 2023 to 2035 period under the proposed requirements using discount rates of 3 and 7 percent.

II. General Information

A. Does this action apply to me?

Categories and entities potentially affected by this action include:

This table is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be affected by this action. Other types of entities not listed in the table could also be affected by this action. To determine whether your entity is affected by this action, you should carefully examine the applicability criteria found in the final rule. If you have questions regarding the applicability of this action to a particular entity, consult the person listed in the FOR FURTHER INFORMATION CONTACT section, your air permitting authority, or your EPA Regional representative listed in 40 CFR 60.4 (General Provisions).

B. How do I obtain a copy of this document, background information, and other related information?

In addition to being available in the docket, an electronic copy of the proposed action is available on the internet. Following signature by the Administrator, the EPA will post a copy of this proposed action at https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry. Following publication in the Federal Register , the EPA will post the Federal Register version of the final rule and key technical documents at this same website. A redline version of the regulatory language that incorporates the proposed changes described in section X for NSPS OOOO and NSPS OOOOa is available in the docket for this action (Docket ID No. EPA-HQ-OAR-2021-0317). The EPA plans to propose the regulatory language for NSPS OOOOb and EG OOOOc through a supplemental action.

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

A. Impacts of GHGs, VOCs and SO ₂ 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 CO ₂ ), VOCs, SO ₂ , NO _X , H ₂ S, CS ₂ , and COS. See 49 FR 2636, 2637 (January 20, 1984). As noted below, to this point, the EPA has focused its regulatory efforts on GHGs, VOC, and SO ₂ . ¹⁰

¹⁰  We note that the EPA's focus on GHGs (in particular methane), VOC, and SO ₂ in these analyses, does not in any way limit the EPA's authority to promulgate standards that would apply to other pollutants emitted from the Crude Oil and Natural Gas source category, if the EPA determines in the future that such action is appropriate.

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 induced GHGs, largely derived from our reliance on fossil fuels, are causing serious and life-threatening environmental and health impacts.

Extensive additional information on climate change is available in the scientific assessments and the EPA documents that are briefly described in this section, 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). ¹¹ 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, CH ₄ , N ₂ O, hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (SF ₆ )—“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 have confirmed and strengthened the understanding and concerns regarding the climate risks considered in the Finding. 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).

¹¹  In describing these 2009 Findings in this proposal, the EPA is neither reopening nor revisiting them.

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  ¹² 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).

¹²  The CAA states in section 302(h) that “[a]ll language referring to effects on welfare includes, but is not limited to, effects on soils, water, crops, vegetation, manmade materials, animals, wildlife, weather, visibility, and climate, damage to and deterioration of property, and hazards to transportation, as well as effects on economic values and on personal comfort and well-being, whether caused by transformation, conversion, or combination with other air pollutants.” 42 U.S.C. 7602(h).

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). ¹³ 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).

¹³  In describing these 2016 Findings in this proposal, the EPA is neither reopening nor revisiting them.

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. ¹⁴ 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:

¹⁴  See later in this section for specific examples. An additional resource for indicators can be found at https://www.epa.gov/climate-indicators.

• U.S. Global Change Research Program's (USGCRP) 2016 Climate and Health Assessment  ¹⁵ and 2017-2018 Fourth National Climate Assessment (NCA4).  ^{16   17}

¹⁵  USGCRP, 2016: The Impacts of Climate Change on Human Health in the United States: A Scientific Assessment. Crimmins, A., J. Balbus, J.L. Gamble, C.B. Beard, J.E. Bell, D. Dodgen, R.J. Eisen, N. Fann, M.D. Hawkins, S.C. Herring, L. Jantarasami, D.M. Mills, S. Saha, M.C. Sarofim, J. Trtanj, and L. Ziska, Eds. U.S. Global Change Research Program, Washington, DC, 312 pp.

¹⁶  USGCRP, 2017: Climate Science Special Report: Fourth National Climate Assessment, Volume I [Wuebbles, D.J., D.W. Fahey, K.A. Hibbard, D.J. Dokken, B.C. Stewart, and T.K. Maycock (eds.)]. U.S. Global Change Research Program, Washington, DC, USA, 470 pp, doi: 10.7930/J0J964J6.

¹⁷  USGCRP, 2018: Impacts, Risks, and Adaptation in the United States: Fourth National Climate Assessment, Volume II [Reidmiller, D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research Program, Washington, DC, USA, 1515 pp. doi: 10.7930/NCA4.2018.

• IPCC's 2018 Global Warming of 1.5 °C, ¹⁸ 2019 Climate Change and Land, ¹⁹ and the 2019 Ocean and Cryosphere in a Changing Climate  ²⁰ assessments, as well as the 2021 IPCC Sixth Assessment Report (AR6). ²¹

¹⁸  IPCC, 2018: Global Warming of 1.5 °C. An IPCC Special Report on the impacts of global warming of 1.5 °C above pre-industrial levels and related global greenhouse gas emission pathways, in the context of strengthening the global response to the threat of climate change, sustainable development, and efforts to eradicate poverty [Masson-Delmotte, V., P. Zhai, H.-O. Pörtner, D. Roberts, J. Skea, P.R. Shukla, A. Pirani, W. Moufouma-Okia, C. Péan, R. Pidcock, S. Connors, J.B.R. Matthews, Y. Chen, X. Zhou, M.I. Gomis, E. Lonnoy, T. Maycock, M. Tignor, and T. Waterfield (eds.)].

¹⁹  IPCC, 2019: Climate Change and Land: an IPCC special report on climate change, desertification, land degradation, sustainable land management, food security, and greenhouse gas fluxes in terrestrial ecosystems [P.R. Shukla, J. Skea, E. Calvo Buendia, V. Masson-Delmotte, H.-O. Pörtner, D.C. Roberts, P. Zhai, R. Slade, S. Connors, R. van Diemen, M. Ferrat, E. Haughey, S. Luz, S. Neogi, M. Pathak, J. Petzold, J. Portugal Pereira, P. Vyas, E. Huntley, K. Kissick, M. Belkacemi, J. Malley, (eds.)].

²⁰  IPCC, 2019: IPCC Special Report on the Ocean and Cryosphere in a Changing Climate [H.-O. Pörtner, D.C. Roberts, V. Masson-Delmotte, P. Zhai, M. Tignor, E. Poloczanska, K. Mintenbeck, A. Alegría, M. Nicolai, A. Okem, J. Petzold, B. Rama, N.M. Weyer (eds.)].

²¹  IPCC, 2021: Summary for Policymakers. In: Climate Change 2021: The Physical Science Basis. Contribution of Working Group I to the Sixth Assessment Report of the Intergovernmental Panel on Climate Change [Masson-Delmotte, V., P. Zhai, A. Pirani, S.L. Connors, C. Péan, S. Berger, N. Caud, Y. Chen, L. Goldfarb, M.I. Gomis, M. Huang, K. Leitzell, E. Lonnoy, J.B.R. Matthews, T.K. Maycock, T. Waterfield, O. Yelekçi, R. Yu and B. Zhou (eds.)]. Cambridge University Press. In Press.

• The NAS 2016 Attribution of Extreme Weather Events in the Context of Climate Change, ²² 2017 Valuing Climate Damages: Updating Estimation of the Social Cost of Carbon Dioxide, ²³ and 2019 Climate Change and Ecosystems  ²⁴ assessments.

²²  National Academies of Sciences, Engineering, and Medicine. 2016. Attribution of Extreme Weather Events in the Context of Climate Change. Washington, DC: The National Academies Press. https://dio.org/10.17226/21852.

²³  National Academies of Sciences, Engineering, and Medicine. 2017. Valuing Climate Damages: Updating Estimation of the Social Cost of Carbon Dioxide. Washington, DC: The National Academies Press. https://doi.org/10.17226/24651.

²⁴  National Academies of Sciences, Engineering, and Medicine. 2019. Climate Change and Ecosystems. Washington, DC: The National Academies Press. https://doi.org/10.17226/25504.

• National Oceanic and Atmospheric Administration's (NOAA) annual State of the Climate reports published by the Bulletin of the American Meteorological Society, ²⁵ most recently in August of 2020.

²⁵  Blunden, J., and D.S. Arndt, Eds., 2020: State of the Climate in 2019. Bull. Amer. Meteor. Soc, S1-S429, https://doi.org/10.1175/2020BAMSStateoftheClimate.1.

• EPA Climate Change and Social Vulnerability in the United States: A Focus on Six Impacts (2021). ²⁶

²⁶  EPA. 2021. Climate Change and Social Vulnerability in the United States: A Focus on Six Impacts. U.S. Environmental Protection Agency, EPA 430-R-21-003.

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 as a result of both historic 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, CO ₂ , measured at Mauna Loa in Hawaii and at other sites around the world reached 414 ppm in 2020 (nearly 50 percent higher than pre-industrial levels), ²⁷ and has continued to rise at a rapid rate. Global average temperature has increased by about 1.1 degrees Celsius (°C) (2.0 degrees Fahrenheit (°F)) in the 2011-2020 decade relative to 1850-1900. ²⁸ The years 2014-2020 were the warmest seven years in the 1880-2020 record, contributing to the warmest decade on record with a decadal temperature of 0.82 °C (1.48 °F) above the 20th century. ^{29   30} 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. ³¹ 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. ³² 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. ³³ Higher CO ₂ 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. ³⁴ 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. ³⁵ 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  ³⁶ in many regions. ³⁷

²⁷   https://climate.nasa.gov/vital-signs/carbon-dioxide/ .

²⁸  IPCC, 2021.

²⁹  NOAA National Centers for Environmental Information, State of the Climate: Global Climate Report for Annual 2020, published online January 2021, retrieved on February 10, 2021 from https://www.ncdc.noaa.gov/sotc/global/202013.

³⁰  Blunden, J., and D.S. Arndt, Eds., 2020: State of the Climate in 2019. Bull. Amer. Meteor. Soc, S1-S429, https://doi.org/10.1175/2020BAMSStateoftheClimate.1.

³¹  IPCC, 2021.

³²  IPCC, 2021.

³³  USGCRP, 2018: Impacts, Risks, and Adaptation in the United States: Fourth National Climate Assessment, Volume II [Reidmiller, D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research Program, Washington, DC, USA, 1515 pp. doi: 10.7930/NCA4.2018.

³⁴  IPCC, 2021.

³⁵  IPCC, 2021.

³⁶  These are drought measures based on soil moisture.

³⁷  IPCC, 2021.

The assessment literature demonstrates that modest additional amounts of warming may lead to a climate different from anything humans have ever experienced. The present-day CO ₂ concentration of 414 ppm is already higher than at any time in the last 2 million years. ³⁸ If concentrations exceed 450 ppm, they would likely be higher than any time in the past 23 million years: ³⁹ 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 CO ₂ concentrations were this high) 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 GHGs 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. ⁴⁰ 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 CO ₂ being absorbed by the ocean has resulted in changes in ocean chemistry due to acidification of a magnitude not seen in 65 million years, ⁴¹ putting many marine species—particularly calcifying species—at risk.

³⁸  IPCC, 2021.

³⁹  IPCC, 2013.

⁴⁰  IPCC, 2021.

⁴¹  IPCC, 2018.

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. ⁴² 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. ⁴³

⁴²  USGCRP, 2018.

⁴³  IPCC, 2018.

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 a hundred 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). ⁴⁴ 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, while the movement speed has decreased, and elevated sea levels have increased coastal flooding, all of which make these tropical cyclones more damaging. ⁴⁵

⁴⁴  IPCC, 2018.

⁴⁵  IPCC, 2021.

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. ⁴⁶ The National Interagency Fire Center has documented U.S. wildfires since 1983, and the ten years with the largest acreage burned have all occurred since 2004. ⁴⁷ 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, but also 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. ⁴⁸

⁴⁶  USGCRP, 2018

⁴⁷  NIFC (National Interagency Fire Center). 2021. Total wildland fires and acres (1983-2020). Accessed August 2021. www.nifc.gov/fireInfo/fireInfo_stats_totalFires.html.

⁴⁸  USGCRP, 2018.

Some GHGs also have impacts beyond those mediated through climate change. For example, elevated concentrations of carbon dioxide 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)  ⁴⁹ and cause ocean acidification. Nitrous oxide depletes the levels of protective stratospheric ozone. ⁵⁰

⁴⁹  Ziska, L., A. Crimmins, A. Auclair, S. DeGrasse, J.F. Garofalo, A.S. Khan, I. Loladze, A.A. Pérez de León, A.Showler, J. Thurston, and I. Walls, 2016: Ch. 7: Food Safety, Nutrition, and Distribution. The Impacts of Climate Change on Human Health in the United States: A Scientific Assessment. U.S. Global Change Research Program, Washington, DC, 189-216. http://dx.doi.org/10.7930/J0ZP4417

⁵⁰  WMO (World Meteorological Organization), Scientific Assessment of Ozone Depletion: 2018, Global Ozone Research and Monitoring Project —Report No. 58, 588 pp., Geneva, Switzerland, 2018.

As methane is the primary GHG addressed in this proposal, it is relevant to highlight some specific trends and impacts specific to methane. Concentrations of methane reached 1879 parts per billion (ppb) in 2020, more than two and a half times the preindustrial concentration of 722 ppb. ⁵¹ Moreover, the 2020 concentration was an increase of almost 13 ppb over 2019—the largest annual increase in methane concentrations of the period since the early 1990s, continuing a trend of rapid rise since a temporary pause ended in 2007. ⁵² Methane has a high radiative efficiency—almost 30 times that of carbon dioxide per ppb (and therefore, 80 times as much per unit mass). ⁵³ 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 carbon dioxide. ⁵⁴ Because of the substantial emissions of methane, and its radiative efficiency, methane mitigation is one of the best opportunities for reducing near term warming.

⁵¹  Blunden et al., 2020.

⁵²  NOAA, https://gml.noaa.gov/webdata/ccgg/trends/ch4/ch4_annmean_gl.txt, accessed August 19th, 2021.

⁵³  IPCC, 2021.

⁵⁴  IPCC, 2021.

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. ⁵⁵ In remote areas, methane is an important precursor to tropospheric ozone formation. ⁵⁶ Approximately 50 percent of the global annual mean ozone increase since preindustrial times is believed to be due to anthropogenic methane. ⁵⁷ Projections of future emissions also indicate that methane is likely to be a key contributor to ozone concentrations in the future. ⁵⁸ 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. ⁵⁹ Reducing methane emissions, therefore, will contribute to efforts to reduce global background ozone concentrations that contribute to the incidence of ozone-related health effects. ⁶⁰ The benefits of such reductions are global and occur in both urban and rural areas.

⁵⁵  Nolte, C.G., P.D. Dolwick, N. Fann, L.W. Horowitz, V. Naik, R.W. Pinder, T.L. Spero, D.A. Winner, and L.H. Ziska, 2018: Air Quality. In Impacts, Risks, and Adaptation in the United States: Fourth National Climate Assessment, Volume II [Reidmiller, D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research Program, Washington, DC, USA, pp. 512-538. doi: 10.7930/NCA4. 2018. CH13

⁵⁶  U.S. EPA. 2013. “Integrated Science Assessment for Ozone and Related Photochemical Oxidants (Final Report).” EPA-600-R-10-076F. National Center for Environmental Assessment—RTP Division. Available at http://www.epa.gov/ncea/isa/.

⁵⁷  Myhre, G., D. Shindell, F.-M. Bréon, W. Collins, J. Fuglestvedt, J. Huang, D. Koch, J.-F. Lamarque, D. Lee, B. Mendoza, T. Nakajima, A. Robock, G. Stephens, T. Takemura and H. Zhang, 2013: Anthropogenic and Natural Radiative Forcing. In: Climate Change 2013: The Physical Science Basis. Contribution of Working Group I to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change [Stocker, T.F., D. Qin, G.-K. Plattner, M. Tignor, S.K. Allen, J. Boschung, A. Nauels, Y. Xia, V. Bex and P.M. Midgley (eds.)]. Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA. Pg. 680.

⁵⁸   Ibid.

⁵⁹   Ibid.

⁶⁰  USGCRP, 2018.

These scientific assessments 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 mitigation.

2. VOC

Many VOC can be classified as HAP ( e.g., benzene), ⁶¹ which can lead to a variety of health concerns such as cancer and noncancer illnesses ( e.g., respiratory, neurological). Further, VOC are one of the key precursors in the formation of ozone. Tropospheric, or ground-level, ozone is formed through reactions of VOC 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. ^{62   63   64   65} 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. ⁶⁶

⁶¹  Benzene Integrated Risk Information System (IRIS) Assessment: https://cfpub.epa.gov/ncea/iris2/chemicalLanding.cfm?substance_nmbr=276.

⁶²  Benedict, K. B., Zhou, Y., Sive, B. C., Prenni, A. J., Gebhart, K. A., Fischer, E. V., . . . & Collett Jr, J. L. 2019. Volatile organic compounds and ozone in Rocky Mountain National Park during FRAPPE. Atmospheric Chemistry and Physics, 19 (1), 499-521.

⁶³  Lindaas, J., Farmer, D. K., Pollack, I. B., Abeleira, A., Flocke, F., & Fischer, E. V. 2019. Acyl peroxy nitrates link oil and natural gas emissions to high ozone abundances in the Colorado Front Range during summer 2015. Journal of Geophysical Research: Atmospheres, 124 (4), 2336-2350.

⁶⁴  McDuffie, E. E., Edwards, P. M., Gilman, J. B., Lerner, B. M., Dubé, W. P., Trainer, M., . . . & Brown, S. S. 2016. Influence of oil and gas emissions on summertime ozone in the Colorado Northern Front Range. Journal of Geophysical Research: Atmospheres, 121 (14), 8712-8729.

⁶⁵  Tzompa‐Sosa, Z. A., & Fischer, E. V. 2021. Impacts of emissions of C2‐C5 alkanes from the US oil and gas sector on ozone and other secondary species. Journal of Geophysical Research: Atmospheres, 126 (1), e2019JD031935.

⁶⁶  National Health Interview Survey (NHIS) Data, 2011. http://www.cdc.gov/asthma/nhis/2011/data.htm.

In the EPA's 2020 Integrated Science Assessment (ISA) for Ozone and Related Photochemical Oxidants, ⁶⁷ the EPA estimates 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.

⁶⁷  Integrated Science Assessment (ISA) for Ozone and Related Photochemical Oxidants (Final Report). U.S. Environmental Protection Agency, Washington, DC, EPA/600/R-20/012, 2020.

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. SO ₂

Current scientific evidence links short-term exposures to SO ₂ , 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.

SO ₂ 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, SO ₂ , 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. ⁶⁸

⁶⁸  U.S. EPA. Integrated Science Assessment (ISA) for Oxides of Nitrogen and Sulfur Ecological Criteria (2008 Final Report). U.S. Environmental Protection Agency, Washington, DC, EPA/600/R-08/082F, 2008.

B. Oil and Natural Gas Industry and Its Emissions

This section 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. Oil and Natural Gas Industry—Structure

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. ^{69   70} The EPA regulates oil refineries as a separate source category; accordingly, as with the previous oil and gas NSPS rulemakings, for purposes of this proposed rulemaking, for crude oil, the EPA's focus is on operations from the well to the point of custody transfer at a petroleum refinery, while for natural gas, the focus is on all operations from the well to the local distribution company custody transfer station commonly referred to as the “city-gate.”  ⁷¹

⁶⁹  The EPA previously described an overview of the sector in section 2.0 of the 2011 Background Technical Support Document to 40 CFR part 60, subpart OOOO, located at Docket ID Item No. EPA-HQ-OAR-2010-0505-0045, and section 2.0 of the 2016 Background Technical Support Document to 40 CFR part 60, subpart OOOOa, located at Docket ID Item No. EPA-HQ-OAR-2010-0505-7631.

⁷⁰  While generally oil and natural gas production includes both onshore and offshore operations, 40 CFR part 60, subpart OOOOa addresses onshore operations.

⁷¹  For regulatory purposes, the EPA defines the Crude Oil and Natural Gas source category to mean (1) Crude oil production, which includes the well and extends to the point of custody transfer to the crude oil transmission pipeline or any other forms of transportation; and (2) Natural gas production, processing, transmission, and storage, which include the well and extend to, but do not include, the local distribution company custody transfer station. The distribution segment is not part of the defined source category.

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, compressors; heater treaters; separators; storage vessels; pneumatic devices; 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.

Of these products, 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. ⁷²

⁷²  See 40 CFR part 60, subparts J and Ja, and 40 CFR part 63, subparts CC and UUU.

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, H ₂ S, CO ₂ , 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 typically is sent to gas processing plants in order to separate NGLs for use as feedstock for petrochemical plants, burned for space heating and cooking, or blended 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 CO ₂ removal, fractionation of NGL, and other processes, such as the capture of CO ₂ 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. ⁷³ 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.

⁷³  The distribution segment is not included in the definition of the Crude Oil and Natural Gas source category that is currently regulated under 40 CFR part 60, subpart OOOOa.

2. Oil and Natural Gas Industry—Emissions

The oil and natural gas industry sector is the largest source of industrial methane emissions in the U.S. ⁷⁴ Natural gas is comprised 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 greenhouse gas; over a 100-year timeframe, it is nearly 30 times more powerful at trapping climate warming heat than CO ₂ , and over a 20-year timeframe, it is 83 times more powerful. ⁷⁵ Because methane is a powerful greenhouse gas 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 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, SO ₂ , NO _X , H ₂ S, CS ₂ , and COS. The year 2016 modeling platform produced by U.S. EPA estimated about 3 million tons of VOC are emitted by oil and gas-related sources. ⁷⁶

⁷⁴  H.R. Rep. No. 117-64, 4 (2021) (Report by the House Committee on Energy and Commerce concerning H.J. Res. 34, to disapprove the 2020 Policy Rule) (House Report).

⁷⁵  IPCC, 2021.

⁷⁶   https://www.epa.gov/sites/default/files/2020-11/documents/2016v1_emismod_tsd_508.pdf.

Emissions of methane and these co-pollutants occur in every segment of the Crude Oil and Natural Gas source category. 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, and pneumatic devices. 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 and intermittent bleed of gas from pneumatic 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 and to destroy methane, which has a high global warming potential, and convert it to CO ₂ which has a lower global warming potential, and to also control other air pollutants such as VOC.

“Super-emitting” events, sites, or equipment, where a small proportion of sources account for a large proportion of overall emissions, can occur throughout the Oil and Natural Gas Industry and have been observed to occur in the equipment types and activities covered by this proposed action. There are a number of definitions for the term “super-emitter.” A 2018 National Academies of Sciences, Engineering, and Medicine report  ⁷⁷ on methane discussed three categories of “high-emitting” sources:

⁷⁷   https://www.nap.edu/download/24987#.

• Routine or “chronic” high-emitting sources, which regularly emit at higher rates relative to “peers” in a sample. Examples include large facilities, or 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 pneumatic 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. ⁷⁸

⁷⁸  Pandey et al. (2019). Satellite observations reveal extreme methane leakage from a natural gas well blowout. PNAS December 26, 2019 116 (52) 26376-26381.

Super-emitters have been observed at many different scales, from site-level to component-level, across many research studies. ⁷⁹ 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. ⁸⁰ 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). ⁸¹ 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 work through its stakeholder process 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”) 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 rule 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.

⁷⁹  See for example, Brandt, A., Heath, G., Cooley, D. (2016) Methane leaks from natural gas systems follow extreme distributions. Environ. Sci. Technol., DOI: 10.1021/acs.est.6b04303; Zavala-Araiza, D., Alvarez, R.A., Lyon, D.R., Allen, D.T., Marchese, A.J., Zimmerle, D.J., & Hamburg, S.P. (2017). Super-emitters in natural gas infrastructure are caused by abnormal process conditions. Nature communications, 8, 14012; Mitchell, A., et al. (2015), Measurements of Methane Emissions from Natural Gas Gathering Facilities and Processing Plants: Measurement Results. Environmental Science & Technology, 49(5), 3219-3227; Allen, D., et al. (2014), Methane Emissions from Process Equipment at Natural Gas Production Sites in the United States: Pneumatic Controllers. Environmental Science & Technology.

⁸⁰  Caulton et al. (2019). Importance of Super-emitter Natural Gas Well Pads in the Marcellus Shale. Environ. Sci. Technol. 2019, 53, 4747-4754; Zavala-Araiza, D., Alvarez, R., Lyon, D, et al. (2016). Super-emitters in natural gas infrastructure are caused by abnormal process conditions. Nat Commun 8, 14012 (2017). https://www.nature.com/articles/ncomms14012; Lyon, et al. (2016). Aerial Surveys of Elevated Hydrocarbon Emissions from Oil and Gas Production Sites. Environ. Sci. Technol. 2016, 50, 4877-4886. https://pubs.acs.org/doi/10.1021/acs.est.6b00705; and Zavala-Araiza D, et al. (2015). Toward a functional definition of methane superemitters: Application to natural gas production sites. 49 ENVTL. SCI. & TECH. 8167, 8168 (2015). https://pubs.acs.org/doi/10.1021/acs.est.5b00133.

⁸¹  The EPA's emission estimates in the GHGI are developed with the best data available at the time of their development, including data from the Greenhouse Gas Reporting Program (GHGRP) in 40 CFR part 98, subpart W, and from recent research studies. GHGRP subpart W emissions data used in the GHGI are quantified by reporters using direct measurements, engineering calculations, or emission factors, as specified by the regulation. The EPA has a multi-step data verification process for GHGRP subpart W data, including automatic checks during data-entry, statistical analyses on completed reports, and staff review of the reported data. Based on the results of the verification process, the EPA follows up with facilities to resolve mistakes that may have occurred.

Below we provide estimated emissions of methane, VOC, and SO ₂ from Oil and Natural Gas Industry operation sources.

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 below presents total U.S. anthropogenic methane emissions for the years 1990, 2010, and 2019.

In accordance with the practice of the EPA GHGI, the EPA GHGRP, and international reporting standards under the UN 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 25 for methane indicates that one ton of methane has approximately as much climate impact over a 100-year period as 25 tons of carbon dioxide. The most recent IPCC AR6 assessment has estimated a slightly larger 100-year GWP of methane of almost 30 (specifically, either 27.2 or 29.8 depending on whether the value includes the carbon dioxide produced by the oxidation of methane in the atmosphere). As mentioned earlier, because methane has a shorter lifetime than carbon dioxide, 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 carbon dioxide: When using the AR6 20-year GWP of 81, which only looks at impacts over the next 20 years, the total US emissions of methane in 2019 would be equivalent to about 2140 MMT CO ₂ .

Table 8 below presents total methane emissions from natural gas production through transmission and storage and petroleum production, for years 1990, 2010, and 2019, in MMT CO ₂ Eq. (or million metric tons CO ₂ Eq.) of methane.

⁸²  Other sources include rice cultivation, forest land, stationary combustion, abandoned oil and natural gas wells, abandoned coal mines, mobile combustion, composting, and several sources emitting less than 1 MMT CO ₂ Eq. in 2019.

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. ⁸³ 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 (48,601 MMT CO2 Eq.) from all sources. ⁸⁴ 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 2018 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 160 other countries. What that means is that the U.S. emits more of a single GHG—methane—from a single sector—the oil and gas sector—than the total combined GHGs emitted by 164 out of 194 total 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 64 of the lowest-emitting countries and territories, using the 2018 Climate Watch data set.

⁸³  The Climate Watch figures presented here come from the PIK PRIMAP-hist dataset included on Climate Watch. The PIK PRIMAP-hist dataset combines the United Nations Framework Convention on Climate Change (UNFCCC) reported data where available and fills gaps with other sources. It does not include land use change and forestry but covers all other sectors. https://www.climatewatchdata.org/ghg-emissions?end_year=2018&source=PIK&start_year=1990.

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 the U.S. regional climate, as well as the global climate as a whole 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 in terms of both absolute emissions, and in comparison to other source categories globally or within the U.S.

The IPCC AR6 assessment determined that “From a physical science perspective, limiting human-induced global warming to a specific level requires limiting cumulative CO ₂ emissions, reaching at least net zero CO ₂ emissions, along with strong reductions in other GHG emissions.” The report also singled out the importance of “strong and sustained CH ₄ 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 SO ₂ . 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.

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 SO ₂ 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 points, including sector, NAICS code, and Source Classification Code. Tables 9 and 10 below present total U.S. VOC and SO ₂ emissions by sector, respectively, for the year 2017, 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 20% of the total VOC emitting by anthropogenic sources). About 2.5 percent of the total U.S. anthropogenic SO ₂ comes from the oil and natural gas sector.

Table 11 below presents total VOC and SO ₂ emissions from oil and natural gas production through transmission and storage, for the year 2017, 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 2017 NEI, the oil and gas sector makes up about 25 percent of the total VOC emissions from anthropogenic sources. The SO ₂ emissions have been declining in just about every anthropogenic sector, but the oil and gas sector is an exception where SO ₂ emissions have been slightly increasing or remaining steady in some cases in recent years.

⁸⁵  Other sources include remaining sources emitting less than 1,000 kt VOC in 2017.

⁸⁶  Other sources include remaining sources emitting less than 100 kt SO ₂ in 2017.

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 rule is CAA section 111, which governs the establishment of standards of performance for stationary sources. This 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 of 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 non-air 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  ⁸⁷ for the 2016 Rule (85 FR 35824, June 3, 2016), 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,”  ⁸⁸ “greater than the industry could bear and survive,”  ⁸⁹ “excessive,”  ⁹⁰ or “unreasonable.”  ⁹¹ These formulations appear to be synonymous, and for convenience, in this rulemaking, as in previous rulemakings, we will use reasonableness as the standard, 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).

⁸⁷  80 FR 56593, 56616 (September 18, 2015).

⁸⁸   Lignite Energy Council, 198 F.3d at 933.

⁸⁹   Portland Cement Ass'n v. EPA, 513 F.2d 506, 508 (D.C. Cir. 1975).

⁹⁰   Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).

⁹¹   Id.

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. ⁹² 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, in evaluating controls for reducing VOC and methane emissions from new sources, we 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. ⁹³ We also evaluated costs at a sector level by assessing the projected new capital expenditures required under the proposal (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. For a detailed discussion of these cost approaches, please see section IX of the proposal preamble.

⁹²  See, e.g., Husqvarna AB v. EPA, 254 F.3d 195, 200 (D.C. Cir. 2001) (where CAA section 213 does not mandate a specific method of cost analysis, the EPA may make a reasoned choice as to how to analyze costs).

⁹³  We believe that both the single and multipollutant approaches are appropriate for assessing the reasonableness of the multipollutant controls considered in this action. The EPA has considered similar approaches in the past when considering multiple pollutants that are controlled by a given control option. See e.g., 80 FR 56616-56617; 73 FR 64079-64083 and EPA Document ID Nos. EPA-HQ-OAR-2004-0022-0622, EPA-HQ-OAR-2004-0022-0447, EPA-HQ-OAR-2004-0022-0448.

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. ⁹⁴ 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.

⁹⁴  The EPA notes that design, equipment, work practice or operational standards established under CAA section 111(h) (commonly referred to as “work practice standards”) reflect the “best technological system of continuous emission reduction” and that this phrasing differs from the “best system of emission reduction” phrase in the definition of “standard of performance” in CAA section 111(a)(1). Although the differences in these phrases may be meaningful in other contexts, for purposes of evaluating the sources and systems of emission reduction at issue in this rulemaking, the EPA has applied these concepts in an essentially comparable manner.

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 section 111(d) as well as 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 section 111(d) implementing regulations several times, most recently on July 8, 2019, 84 FR 32520 (codified at 40 CFR part 60, subpart Ba). ⁹⁵ 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, and their precursors, like VOC)  ⁹⁶ or 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 this provision of CAA section 111(d). See 40 CFR 60.21a(b).

⁹⁵  Subpart Ba provides for the applicability of its provisions upon final publication of an EG if such EG is published after July 8, 2019. § 60.20a(a). The EPA acknowledges that the D.C. Circuit has vacated certain timing provisions within subpart Ba. Am. Lung Assoc. v. EPA, 985 F.3d 914 (D.C. Cir. 2021), petition for cert. pending, No. 20-1778 (filed June 23, 2001) ( Am. Lung Assoc. ). However, the court did not vacate the applicability provision, therefore subpart Ba applies to any EG finalized from this proposal. The Agency plans to undertake rulemaking to address the provisions vacated under the court's decision in the near future.

⁹⁶  VOC are not listed as CAA section 108(a) pollutants, but they are regulated precursors to photochemical oxidants ( e.g., ozone) and particulate matter (PM), both of which are listed CAA section 108(a) pollutants, and VOC therefore fall within the CAA 108(a) exclusion. Accordingly, promulgation of NSPS for VOC does not trigger the application of CAA section 111(d).

While States are authorized to establish standards of performance for designated facilities, there is a fundamental obligation under CAA section 111(d) that such standards of performance reflect the degree of emission limitation achievable through the application of the BSER, as determined by the Administrator. This obligation derives from the definition of “standard of performance” under CAA section 111(a)(1), which makes no distinction between new-source and existing-source standards. 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 remaining useful life and other factors.

After the EPA issues final EG per the requirements under CAA section 111(d) and 40 CFR part 60, subpart Ba, States are required to submit 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 that State. ⁹⁷ If 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 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).

⁹⁷  CAA section 111(d)(2)(A).

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  ⁹⁸ 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. ⁹⁹ 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 that Tribe. ¹⁰⁰

⁹⁸  The EPA is aware of many oil and natural gas operations located in Indian Country.

⁹⁹  See 40 CFR part 49, subpart A.

¹⁰⁰  CAA section 111(d)(2)(A).

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. ¹⁰¹ 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).

¹⁰¹  See 44 FR 49222 (August 21, 1979).

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 SO ₂ Emissions From Natural Gas Processing Units

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 SO ₂ 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 SO ₂ 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 operated pneumatic 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

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”). ^102 103 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 at 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 at 35832. In addition, because this rule was 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 to regulate GHG emissions from the source category. 81 FR at 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 to promulgate a GHGs NSPS. 81 FR at 35843.

¹⁰²  The June 3, 2016, rulemaking also included certain final amendments to 40 CFR part 60, subpart OOOO, to address issues on which the EPA had granted reconsideration.

¹⁰³  The EPA review which resulted in the 2016 NSPS OOOOa rule was instigated by a series of directives from then-President Obama targeted at reducing GHGs, including methane: The President's Climate Action Plan (June 2013); the President's Climate Action Plan: Strategy to Reduce Methane Emissions (“Methane Strategy”) (March 2014); and the President's goal to address, propose and set standards for methane and ozone-forming emissions from new and modified sources in the sector (January 2015, https://obamawhitehouse.archives.gov/the-press-office/2015/01/14/fact-sheet-Administration-takes-steps-forward-climate-action-plan-anno-1 ).

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 (pneumatic 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 emission 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.

Petitions for judicial review and to reconsider. Following promulgation of the 2016 NSPS OOOOa rule, several states and industry associations challenged the 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. ¹⁰⁴ 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. As explained below, all litigation challenging the 2016 NSPS OOOOa rule is currently stayed.

¹⁰⁴  See Docket ID Item Nos.: EPA-HQ-OAR-2010-0505-7682, EPA-HQ-OAR-2010-0505-7683, EPA-HQ-OAR-2010-0505-7684, EPA-HQ-OAR-2010-0505-7685, EPA-HQ-OAR-2010-0505-7686.

5. 2020 Policy and Technical Rules

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 at 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 at 57030. The second was that the rule interpreted 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 at 57034. The 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 at 57038. ¹⁰⁵

¹⁰⁵  Following the promulgation of the 2020 Policy Rule, the EPA promulgated a final rule that identified a standard or criteria for determining which contributions are “significant,” which the D.C. Circuit vacated. “Pollutant-Specific Significant Contribution Finding for Greenhouse Gas Emissions From New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units, and Process for Determining Significance of Other New Source Performance Standards Source Categories.” 86 FR 2542 (Jan. 13, 2021), vacated by California v. EPA, No. 21-1035 (D.C. Cir.) (Order, April 5, 2021, Doc. #1893155).

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.

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.

Litigation. Several States and non-governmental organizations 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 below), the court granted petitioners motion to voluntarily dismiss their cases. Id. ECF Dkt #1911437. All petitions for review regarding the 2020 Technical Rule were consolidated into a different case in the D.C. Circuit. Environmental Defense Fund, 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 EPA's rulemaking actions in response to E.O. 13990 and pending the conclusion of EPA's potential reconsideration of the 2020 Technical Rule. Id. ECF Dkt #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 Dkt #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. ¹⁰⁶ 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 Dkt #1875192.

¹⁰⁶  When the EPA issued the 2016 NSPS OOOOa rule, a challenge to the 2012 NSPS OOOO rule for failing to regulate methane was severed and assigned to a separate case, NRDC v. EPA, No. 16-1425 (D.C. Cir.), pending judicial review of the 2016 NSPS OOOOa in American Petroleum Institute v. EPA, No. 13-1108 (D.C. Cir.).

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, ¹⁰⁷ disapproving the 2020 Policy Rule. ¹⁰⁸ 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.

¹⁰⁷  The Congressional Review Act was adopted in Subtitle E of the Small Business Regulatory Enforcement Fairness Act of 1996.

¹⁰⁸  “Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources Review,” 85 FR 57018 (Sept. 14, 2020) (“2020 Policy Rule”).

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 sections VIII and X the EPA discusses the impact of the CRA resolution, and identifies and proposes 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. Related Emissions Reduction Efforts

This section summarizes related State actions and other Federal actions regulating oil and natural gas emissions sources and summarizes industry and voluntary efforts to reduce climate change. The proposed NSPS OOOOb and EG OOOOc include specific measures that build on the experience and knowledge the Agency and industry have gained through voluntary programs, as well as the leadership of the States in pioneering new regulatory programs. The proposed 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 proactive regulatory and voluntary efforts. The EPA intends that the requirements proposed in this document will spur all industry stakeholders in all parts of the country to apply these readily available and cost-effective measures.

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

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 its 2012 NSPS and subsequent 2016 NSPS. The EPA further acknowledges the technical innovations that the Oil and Natural Gas Industry has made during the past decade; this industry is fast-paced and constantly changing based on the latest technology. The EPA commends these efforts and recognizes States for their innovative standards, alternative compliance options, and implementation strategies. The EPA recognizes that any one effort will not be enough to address the increasingly dangerous impacts of climate change on public health and welfare and believes that consistent Federal regulation of the Crude Oil and Natural Gas source category plays an important role. To have a meaningful impact on climate change and its impact to human health and the environment, a multifaceted approach needs to be taken to ensure methane reductions will be realized. The EPA also recognizes that States and other Federal agencies regulate in accordance with their own authorities and within their own respective jurisdictions, and collectively do not fully address the range of sources and emission reduction measures contained in this proposal. Direct Federal regulation of methane from new sources combined with the approved State plans that are consistent with the EPA's EG for existing sources will bring national consistency to level the regulatory playing field, 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 can be obtained. The EPA is committed to working within its authority to provide opportunities to align its programs with other existing State and Federal programs to reduce unnecessary regulatory redundancy where appropriate.

Among assessing various studies and emissions data, the EPA reviewed many current and proposed State regulatory programs to identify potential regulatory options that could be considered for BSER. ¹⁰⁹ For example, the EPA reviewed California, Colorado, and Canadian regulations, as well as a pending proposed rule in New Mexico, that require non-emitting pneumatic devices at certain facilities and in certain circumstances. The EPA also examined California, Colorado, New Mexico (proposed), Pennsylvania, Wyoming, and the Bureau of Land Management (BLM) standards for liquids unloading events. Some of these States have led the way in regulating emissions sources that were not yet subject to requirements under the NSPS OOOOa. For example, Colorado requires the use of best management practices to minimize hydrocarbon emissions and the need for well venting associated with downhole well maintenance and liquids unloading, unless venting is necessary for safety. Other States, such as New Mexico, are evaluating similar requirements. Other States have requirements for emission sources currently regulated under NSPS OOOOa that are more stringent. For example, California and Colorado require continuous bleed natural gas-driven pneumatic controllers be non-emitting, with specified exceptions. We recognize that, in some cases, the EPA's proposed NSPS and/or EG may be more stringent than existing programs and, in other cases, may be less stringent than existing programs. After careful review and consideration of State regulatory programs in place and proposed State regulations, we are proposing NSPS and EG that, when implemented, will reduce emissions of harmful air pollutants, promote gas capture and beneficial use, and provide opportunity for flexibility and expanded transparency in order to yield a consistent and accountable national program that provides a clear path for States and other Federal agencies to further partner to ensure their programs work in conjunction with each other.

¹⁰⁹  The NSPS OOOOb and EG TSD provides a high-level summary of the state programs that the agency assessed for purposes of this proposal.

As an example of how the EPA strives to work with sources in States that have overlapping regulations for the Oil and Natural Gas Industry, the 2020 Technical Rule included approval of certain State programs as alternatives to certain requirements in the Federal NSPS. Subject to certain caveats, the EPA deemed certain fugitive emissions standards for well sites and compressor stations located in specific States equivalent to the NSPS in an effort to reduce any regulatory burden imposed by duplicative State and Federal regulations. See 40 CFR 60.5399a. The EPA worked extensively with States and reviewed many details of many State programs in this effort. Further, the 2020 Technical Rule amended 40 CFR part 60, subpart OOOOa, to incorporate a process that allows other States not already listed in 40 CFR 60.5399a to request approval of their fugitive monitoring program as an alternative to the NSPS. The EPA is proposing to include a similar request and approval process in NSPS OOOOb. Further, the EPA plans to work closely with States as they develop their State plans pursuant to the EG to look for opportunities to reduce unnecessary administrative burden imposed by redundant and duplicative regulatory requirements and help States that want to establish more stringent standards.

In addition to States, certain Federal agencies also regulate aspects of the oil and natural gas industry pursuant to their own authorities and have other established programs affecting the industry. The EPA believes that Federal regulatory actions and efforts will provide other environmental co- benefits, but the EPA recognizes itself to be the Federal agency that has primary responsibility to protect human health and the environment and has been given the unique responsibility and authority by Congress to address the suite of harmful air pollutants associated with this source category. The EPA further believes that to have a meaningful impact to address the dangers of climate change, it is going to require an “all hands-on deck” effort across all States and all Federal agencies. The EPA has maintained an ongoing dialogue with its Federal partners during the development of this proposed rule to minimize any potential regulatory conflicts and to minimize confusion and regulatory burden on the part of owners and operators. The below description summarizes other agencies' regulations and other established Federal programs.

The U.S. Department of the Interior (DOI) regulates the extraction of oil and gas from Federal lands. Bureaus within the DOI include BLM and the Bureau of Ocean Energy Management (BOEM). 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 an 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. Pursuant to a delegation of Secretarial authority, the BLM also oversees oil and gas operations on many Indian/Tribal leases. 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 are found at 43 CFR 3162.5. The BLM does not directly regulate emissions for the purposes of air quality. However, BLM does regulate venting and flaring of natural gas for the purposes of preventing waste. The governing Resource Management Plan may require lessees to follow State and the EPA emissions regulations. An operator may be required to control/mitigate emissions as a condition of approval (COA) on a drilling permit. The need for such a COA is determined by the environmental review process. The BLM's rules governing the venting and flaring of gas are contained in NTL-4A, which was issued in 1980. Under NTL-4A, limitations on royalty-free venting and flaring constitute the primary mechanism for addressing the surface waste of gas. In 2016, the BLM replaced NTL-4A with a new rule governing venting and flaring (“Waste Prevention Rule”). In addition to restricting royalty-free flaring, the rule set emissions standards for tanks and pneumatic equipment and established LDAR requirements. In 2020, a U.S. District Court of Wyoming largely vacated that rule, thereby reinstating NTL-4A. 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.

The 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  ¹¹⁰ and the North Slope Borough of Alaska. ¹¹¹ BOEM also has air jurisdiction in Federal waters on the Outer Continental Shelf 3-9 miles offshore (depending on 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/.

¹¹⁰  The CAA gave BOEM air jurisdiction west of 87.5° longitude in the Gulf of Mexico region.

¹¹¹  The Consolidated Appropriations Act of 2012 gave BOEM air jurisdiction in the North Slope Borough of Alaska.

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 2.6 million miles of natural gas and hazardous liquid transportation pipelines. When pipelines are maintained, the likelihood of environmental releases like leaks are reduced. ¹¹² 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/.

¹¹²  See Final Report on Leak Detection Study to PHMSA. December 10, 2012. https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/16691/leak-detection-study.pdf.

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, ¹¹³ and oil. ¹¹⁴ FERC also reviews proposals to build liquefied natural gas terminals and interstate natural gas pipelines as well as licensing hydropower projects. The Commission'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. The Commission'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/.

¹¹³   https://www.ferc.gov/industries-data/natural-gas.

¹¹⁴   https://www.ferc.gov/industries-data/oil.

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. Specifically, over 100 oil and natural gas companies participate in the EPA Natural Gas STAR and Methane Challenge partnership programs. 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. ¹¹⁵ Firms might participate in voluntary environmental programs for a variety of reasons, including attracting customers, employees, and investors who value more environmental-responsible goods and services; finding approaches to improve efficiency and reduce costs; and preparing for or helping inform future regulations. ^{116   117}

¹¹⁵  Highwood Emissions Management (2021). “Voluntary Emissions Reduction Initiatives for Responsibly Sourced Oil and Gas.” Available for download at: https://highwoodemissions.com/research/ .

¹¹⁶  Borck, J.C. and C. Coglianese (2009). “Voluntary Environmental Programs: Assessing Their Effectiveness.” Annual Review of Environment and Resources 34(1): 305-324.

¹¹⁷  Brouhle, K., C. Griffiths, and A. Wolverton. (2009). “Evaluating the role of EPA policy levers: An examination of a voluntary program and regulatory threat in the metal-finishing industry.” Journal of Environmental Economics and Management. 57(2): 166-181.

The EPA's Natural Gas STAR Program started in 1993 and seeks to achieve methane emission reductions through implementation of cost-effective best practices and technologies. Partner companies document their voluntary emission reduction activities and can report their accomplishments to the EPA annually. Natural Gas STAR includes over 90 partners across the natural gas value chain. Through 2019 partner companies report having eliminated nearly 1.7 trillion cubic feet of methane emissions since 1993.

The EPA's Methane Challenge Program was launched in 2016 and expands on the Natural Gas STAR Program with ambitious, quantifiable commitments and detailed, transparent reporting and partner recognition. Annually Methane Challenge partners submit facility-level reports that characterize the methane emission sources at their facilities and detail voluntary actions taken to reduce methane emissions. The EPA emphasizes the importance of transparency with the publication of these facility-level data. Although this program includes nearly 70 companies from all segments of the industry, most partners operate in the transmission and distribution segments.

Other voluntary programs for the oil and natural gas industry are administered by diverse organizations, including trade associations and non-profits. While the field of voluntary initiatives continues to grow, it is difficult to understand the present, and potential future, impact these initiatives will have on reducing methane emissions as the majority of these initiatives publish aggregated program-level data. The EPA recognizes the voluntary efforts of industry in reducing methane emissions beyond what is required by current regulations and in significantly expanding the understanding of methane mitigation measures. While progress has been made, there is still considerable remaining need to further reduce methane emissions from the Industry.

VI. Environmental Justice Considerations, Implications, and Stakeholder Outreach

To better inform this proposed rulemaking, the EPA assessed the characteristics of populations living near sources affected by the rule and conducted extensive outreach to overburdened and underserved communities and to environmental justice organizations. During our engagement with communities, concerns were raised regarding health effects of air pollutants, implications of climate change on lifestyle changes, water quality, or extreme heat events, and accessibility to data and information regarding sources near their homes. The EPA then considered this input along with other stakeholder input in designing the proposed rule. For example, one key issue identified through stakeholder input is the use of cutting-edge technologies for methane detection that can allow for rapid detection of high-emitting sources. As described below, the EPA is proposing to allow the use of such technologies in this rule, alongside a rigorous fugitive emissions monitoring program that is based on traditional OGI technology. Another key concern the Agency heard is addressing large emission sources faster, which, in addition to seeking more information on new detection technologies, the EPA is proposing to address with more frequent monitoring at sites with more emissions. The EPA also heard that adjacent communities are concerned about health impacts, and the EPA is proposing rigorous guidelines for pollution sources at existing facilities, methane standards for storage vessels, strengthened and expanded standards for pneumatic controllers, and standards for liquids unloading events that will further reduce emissions of those pollutants. These are just a few examples of how this proposed rule provides benefits to communities; section XII provides a full explanation and rationale of the proposed actions.

E.O. 12898 directs the EPA to identify the populations of concern who are most likely to experience unequal burdens from environmental harms; specifically, minority populations, low-income populations, and indigenous peoples. 59 FR 7629 (February 16, 1994). Additionally, E.O. 13985 was signed in 2021 to advance racial equity and support underserved communities—including people of color and others who have been historically underserved, marginalized, and adversely affected by persistent poverty and inequality—through Federal Government actions. 86 FR 7009 (January 20, 2021). With respect to climate change, E.O. 14008, titled “Tackling Climate Change at Home and Abroad,” was signed on January 27, 2021, stating that climate considerations shall be an essential element of United States foreign policy and national security, working in partnership with foreign governments, States, territories, and local governments, and communities potentially impacted by climate change. The EPA defines environmental justice (EJ) as the fair treatment and meaningful involvement of all people regardless of race, color, national origin, or income with respect to the development, implementation, and enforcement of environmental laws, regulations, and policies. The EPA further defines the term fair treatment to mean that “no group of people should bear a disproportionate burden of environmental harms and risks, including those resulting from the negative environmental consequences of industrial, governmental, and commercial operations or programs and policies” ( https://www.epa.gov/environmentaljustice ). In recognizing that minority and low-income populations often bear an unequal burden of environmental harms and risks, the EPA continues to consider ways of protecting them from adverse public health and environmental effects of air pollution emitted from sources within the Oil and Natural Gas Industry that are addressed in this proposed rulemaking.

A. Environmental Justice and the Impacts of Climate Change

In 2009, under the Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act (“Endangerment Finding”, 74 FR 66496), the Administrator considered how climate change threatens the health and welfare of the U.S. population. ¹¹⁸ As part of that consideration, she also considered risks to minority and low-income individuals and communities, finding that certain parts of the U.S. population may be especially vulnerable based on their characteristics or circumstances. These groups include economically and socially disadvantaged communities, including those that have been historically marginalized or overburdened; individuals at vulnerable lifestages, such as the elderly, the very young, and pregnant or nursing women; those already in poor health or with comorbidities; the disabled; those experiencing homelessness, mental illness, or substance abuse; and/or Indigenous or minority populations dependent on one or limited resources for subsistence due to factors including but not limited to geography, access, and mobility.

¹¹⁸  Earlier studies and reports can be found at https://www.epa.gov/cira/social-vulnerability-report.

Scientific assessment reports produced over the past decade by the USGCRP, ^{119   120} the IPCC, ^{121   122   123   124} the National Academies of Science, Engineering, and Medicine, ^{125   126} and the EPA  ¹²⁷ add more evidence that the impacts of climate change raise potential EJ concerns. These reports conclude that less-affluent, traditionally marginalized and predominantly non-White communities can be especially vulnerable to climate change impacts because they tend to have limited resources for adaptation, are more dependent on climate-sensitive resources such as local water and food supplies, or have less access to social and information resources. Some communities of color, specifically populations defined jointly by ethnic/racial characteristics and geographic location ( e.g., African-American, Black, and Hispanic/Latino communities; Native Americans, particularly those living on Tribal lands and Alaska Natives), may be uniquely vulnerable to climate change health impacts in the U.S., as discussed below. In particular, the 2016 scientific assessment on the Impacts of Climate Change on Human Health   ¹²⁸ found with high confidence that vulnerabilities are place- and time-specific, lifestages and ages are linked to immediate and future health impacts, and social determinants of health are linked to greater extent and severity of climate change-related health impacts.

¹¹⁹  USGCRP, 2018: Impacts, Risks, and Adaptation in the United States: Fourth National Climate Assessment, Volume II [Reidmiller, D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research Program, Washington, DC, USA, 1515 pp. doi: 10.7930/NCA4.2018.

¹²⁰  USGCRP, 2016: The Impacts of Climate Change on Human Health in the United States: A Scientific Assessment. Crimmins, A., J. Balbus, J.L. Gamble, C.B. Beard, J.E. Bell, D. Dodgen, R.J. Eisen, N. Fann, M.D. Hawkins, S.C. Herring, L. Jantarasami, D.M. Mills, S. Saha, M.C. Sarofim, J. Trtanj, and L. Ziska, Eds. U.S. Global Change Research Program, Washington, DC, 312 pp. http://dx.doi.org/10.7930/J0R49NQX.

¹²¹  Oppenheimer, M., M. Campos, R. Warren, J. Birkmann, G. Luber, B. O'Neill, and K. Takahashi, 2014: Emergent risks and key vulnerabilities. In: Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part A: Global and Sectoral Aspects. Contribution of Working Group II to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change [Field, C.B., V.R. Barros, D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, pp. 1039-1099.

¹²²  Porter, J.R., L. Xie, A.J. Challinor, K. Cochrane, S.M. Howden, M.M. Iqbal, D.B. Lobell, and M.I. Travasso, 2014: Food security and food production systems. In: Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part A: Global and Sectoral Aspects. Contribution of Working Group II to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change [Field, C.B., V.R. Barros, D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, pp. 485-533.

¹²³  Smith, K.R., A. Woodward, D. Campbell-Lendrum, D.D. Chadee, Y. Honda, Q. Liu, J.M. Olwoch, B. Revich, and R. Sauerborn, 2014: Human health: impacts, adaptation, and co-benefits. In: Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part A: Global and Sectoral Aspects. Contribution of Working Group II to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change [Field, C.B., V.R. Barros, D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, pp. 709-754.

¹²⁴  IPCC, 2018: Global Warming of 1.5 °C. An IPCC Special Report on the impacts of global warming of 1.5 °C above pre-industrial levels and related global greenhouse gas emission pathways, in the context of strengthening the global response to the threat of climate change, sustainable development, and efforts to eradicate poverty [Masson-Delmotte, V., P. Zhai, H.-O. Pörtner, D. Roberts, J. Skea, P.R. Shukla, A. Pirani, W. Moufouma-Okia, C. Péan, R. Pidcock, S. Connors, J.B.R. Matthews, Y. Chen, X. Zhou, M.I. Gomis, E. Lonnoy, T. Maycock, M. Tignor, and T. Waterfield (eds.)]. In Press.

¹²⁵  National Research Council. 2011. America's Climate Choices. Washington, DC: The National Academies Press. https://doi.org/10.17226/12781.

¹²⁶  National Academies of Sciences, Engineering, and Medicine. 2017. Communities in Action: Pathways to Health Equity. Washington, DC: The National Academies Press. https://doi.org/10.17226/24624.

¹²⁷  EPA. 2021. Climate Change and Social Vulnerability in the United States: A Focus on Six Impacts. U.S. Environmental Protection Agency, EPA 430-R-21-003.

¹²⁸  USGCRP, 2016: The Impacts of Climate Change on Human Health in the United States: A Scientific Assessment.

Per the NCA4, “Climate change affects human health by altering exposures to heat waves, floods, droughts, and other extreme events; vector-, food- and waterborne infectious diseases; changes in the quality and safety of air, food, and water; and stresses to mental health and well-being.”  ¹²⁹ Many health conditions such as cardiopulmonary or respiratory illness and other health impacts are associated with and exacerbated by an increase in GHGs and climate change outcomes, which is problematic as these diseases occur at higher rates within vulnerable communities. Importantly, negative public health outcomes include those that are physical in nature, as well as mental, emotional, social, and economic.

¹²⁹  Ebi, K.L., J.M. Balbus, G. Luber, A. Bole, A. Crimmins, G. Glass, S. Saha, M.M. Shimamoto, J. Trtanj, and J.L. White-Newsome, 2018: Human Health. In Impacts, Risks, and Adaptation in the United States: Fourth National Climate Assessment, Volume II [Reidmiller, D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research Program, Washington, DC, USA, pp. 539-571. doi: 10.7930/NCA4.2018.CH14.

The scientific assessment literature, including the aforementioned reports, demonstrates that there are myriad ways in which these populations may be affected at the individual and community levels. Outdoor workers, such as construction or utility workers and agricultural laborers, who are frequently part of already at-risk groups, are exposed to poor air quality and extreme temperatures without relief. Furthermore, individuals within EJ populations of concern face greater housing and clean water insecurity and bear disproportionate economic impacts and health burdens associated with climate change effects. They also have less or limited access to healthcare and affordable, adequate health or homeowner insurance. The urban heat island effect can add additional stress to vulnerable populations in densely populated cities who do not have access to air conditioning. ¹³⁰ Finally, resiliency and adaptation are more difficult for economically disadvantaged communities: They tend to have less liquidity, individually and collectively, to move or to make the types of infrastructure or policy changes necessary to limit or reduce the hazards they face. They frequently face systemic, institutional challenges that limit their power to advocate for and receive resources that would otherwise aid in resiliency and hazard reduction and mitigation.

¹³⁰  USGCRP, 2016.

The assessment literature cited in the EPA's 2009 Endangerment Finding, as well as Impacts of Climate Change on Human Health, also concluded that certain populations and people in particular stages of life, including children, are most vulnerable to climate-related health effects. The assessment literature produced from 2016 to the present strengthens these conclusions by providing more detailed findings regarding related vulnerabilities and the projected impacts youth may experience. These assessments—including the NCA4 (2018) and The Impacts of Climate Change on Human Health in the United States (2016)—describe how children's unique physiological and developmental factors contribute to making them particularly vulnerable to climate change. Impacts to children are expected from air pollution, infectious and waterborne illnesses, and mental health effects resulting from extreme weather events. In addition, children are among those especially susceptible to allergens, as well as health effects associated with heat waves, storms, and floods. Additional health concerns may arise in low-income households, especially those with children, if climate change reduces food availability and increases prices, leading to food insecurity within households. More generally, these reports note that extreme weather and flooding can cause or exacerbate poor health outcomes by affecting mental health because of stress; contributing to or worsening existing conditions, again due to stress or also as a consequence of exposures to water and air pollutants; or by impacting hospital and emergency services operations. ¹³¹ Further, in urban areas in particular, flooding can have significant economic consequences due to effects on infrastructure, pollutant exposures, and drowning dangers. The ability to withstand and recover from flooding is dependent in part on the social vulnerability of the affected population and individuals experiencing an event. ¹³²

¹³¹  Ebi, K.L., J.M. Balbus, G. Luber, A. Bole, A. Crimmins, G. Glass, S. Saha, M.M. Shimamoto, J. Trtanj, and J.L. White-Newsome, 2018: Human Health. In Impacts, Risks, and Adaptation in the United States: Fourth National Climate Assessment, Volume II [Reidmiller, D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research Program, Washington, DC, USA, pp. 539-571. doi: 10.7930/NCA4.2018.CH14.

¹³²  National Academies of Sciences, Engineering, and Medicine 2019. Framing the Challenge of Urban Flooding in the United States. Washington, DC: The National Academies Press. https://doi.org/10.17226/25381.

The Impacts of Climate Change on Human Health (USGCRP, 2016) also found that some communities of color, low-income groups, people with limited English proficiency, and certain immigrant groups (especially those who are undocumented) live with many of the factors that contribute to their vulnerability to the health impacts of climate change. While difficult to isolate from related socioeconomic factors, race appears to be an important factor in vulnerability to climate-related stress, with elevated risks for mortality from high temperatures reported for Black or African-American individuals compared to White individuals after controlling for factors such as air conditioning use. Moreover, people of color are disproportionately exposed to air pollution based on where they live, and disproportionately vulnerable due to higher baseline prevalence of underlying diseases such as asthma, so climate exacerbations of air pollution are expected to have disproportionate effects on these communities. Locations with greater health threats include urban areas (due to, among other factors, the “heat island” effect where built infrastructure and lack of green spaces increases local temperatures), areas where airborne allergens and other air pollutants already occur at higher levels, and communities experienced depleted water supplies or vulnerable energy and transportation infrastructure.

The recent EPA report on climate change and social vulnerability  ¹³³ examined four socially vulnerable groups (individuals who are low income, minority, without high school diplomas, and/or 65 years and older) and their exposure to several different climate impacts (air quality, coastal flooding, extreme temperatures, and inland flooding). This report found that Black and African-American individuals were 40% more likely to currently live in areas with the highest projected increases in mortality rates due to climate-driven changes in extreme temperatures, and 34% more likely to live in areas with the highest projected increases in childhood asthma diagnoses due to climate-driven changes in particulate air pollution. The report found that Hispanic and Latino individuals are 43% more likely to live in areas with the highest projected labor hour losses in weather-exposed industries due to climate-driven warming, and 50% more likely to live in coastal areas with the highest projected increases in traffic delays due to increases in high-tide flooding. The report found that American Indian and Alaska Native individuals are 48% more likely to live in areas where the highest percentage of land is projected to be inundated due to sea level rise, and 37% more likely to live in areas with high projected labor hour losses. Asian individuals were found to be 23% more likely to live in coastal areas with projected increases in traffic delays from high-tide flooding. Those with low income or no high school diploma are about 25% more likely to live in areas with high projected losses of labor hours, and 15% more likely to live in areas with the highest projected increases in asthma due to climate-driven increases in particulate air pollution, and in areas with high projected inundation due to sea level rise.

¹³³  EPA. 2021. Climate Change and Social Vulnerability in the United States: A Focus on Six Impacts. U.S. Environmental Protection Agency, EPA 430-R-21-003.

Impacts of Climate Change on Indigenous Communities. Indigenous communities face disproportionate risks from the impacts of climate change, particularly those communities impacted by degradation of natural and cultural resources within established reservation boundaries and threats to traditional subsistence lifestyles. Indigenous communities whose health, economic well-being, and cultural traditions depend upon the natural environment will likely be affected by the degradation of ecosystem goods and services associated with climate change. The IPCC indicates that losses of customs and historical knowledge may cause communities to be less resilient or adaptable. ¹³⁴ The NCA4 (2018) noted that while indigenous peoples are diverse and will be impacted by the climate changes universal to all Americans, there are several ways in which climate change uniquely threatens indigenous peoples' livelihoods and economies. ¹³⁵ In addition, there can be institutional barriers (including policy-based limitations and restrictions) to their management of water, land, and other natural resources that could impede adaptive measures.

¹³⁴  Porter et al., 2014: Food security and food production systems.

¹³⁵  Jantarasami, L.C., R. Novak, R. Delgado, E. Marino, S. McNeeley, C. Narducci, J. Raymond-Yakoubian, L. Singletary, and K. Powys Whyte, 2018: Tribes and Indigenous Peoples. In Impacts, Risks, and Adaptation in the United States: Fourth National Climate Assessment, Volume II [Reidmiller, D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research Program, Washington, DC, USA, pp. 572-603. doi: 10.7930/NCA4. 2018. CH15.

For example, indigenous agriculture in the Southwest is already being adversely affected by changing patterns of flooding, drought, dust storms, and rising temperatures leading to increased soil erosion, irrigation water demand, and decreased crop quality and herd sizes. The Confederated Tribes of the Umatilla Indian Reservation in the Northwest have identified climate risks to salmon, elk, deer, roots, and huckleberry habitat. Housing and sanitary water supply infrastructure are vulnerable to disruption from extreme precipitation events. Confounding general Native American response to natural hazards are limitations imposed by policies such as the Dawes Act of 1887 and the Indian Reorganization Act of 1934, which ultimately restrict Indigenous peoples' autonomy regarding land-management decisions through Federal trusteeship of certain Tribal lands and mandated Federal oversight of management decisions. Additionally, NCA4 noted that Indigenous peoples are subjected to institutional racism effects, such as poor infrastructure, diminished access to quality healthcare, and greater risk of exposure to pollutants. Consequently, Native Americans often have disproportionately higher rates of asthma, cardiovascular disease, Alzheimer's disease, diabetes, and obesity. These health conditions and related effects ( e.g., disorientation, heightened exposure to PM _2.5 , etc.) can all contribute to increased vulnerability to climate-driven extreme heat and air pollution events, which also may be exacerbated by stressful situations, such as extreme weather events, wildfires, and other circumstances.

NCA4 and IPCC's Fifth Assessment Report  ¹³⁶ also highlighted several impacts specific to Alaskan Indigenous Peoples. Coastal erosion and permafrost thaw will lead to more coastal erosion, rendering winter travel riskier and exacerbating damage to buildings, roads, and other infrastructure—impacts on archaeological sites, structures, and objects that will lead to a loss of cultural heritage for Alaska's indigenous people. In terms of food security, the NCA4 discussed reductions in suitable ice conditions for hunting, warmer temperatures impairing the use of traditional ice cellars for food storage, and declining shellfish populations due to warming and acidification. While the NCA4 also noted that climate change provided more opportunity to hunt from boats later in the fall season or earlier in the spring, the assessment found that the net impact was an overall decrease in food security.

¹³⁶  Porter et al., 2014: Food security and food production systems.

B. Impacted Stakeholders

Based on analyses of exposed populations, the EPA has determined that this action, if finalized in a manner similar to what is proposed in this document, is likely to help reduce adverse effects of air pollution on minority populations, and/or low-income populations that have the potential for disproportionate impacts, as specified in E.O. 12898 (59 FR 7629, February 16, 1994) and referenced in E.O. 13985 (86 FR 7009, January 20, 2021). The EPA remains committed to engaging with communities and stakeholders throughout the development of this rulemaking and continues to invite comments on how the Agency can better achieve these goals through this action. For this proposed rule, we assessed emissions of HAP, criteria pollutants, and pollutants that cause climate change.

For HAP emissions, we estimated cancer risks and the demographic breakdown of people living in areas with potentially elevated risk levels by performing dispersion modeling of the most recent NEI data from 2017, which indicates nationwide emissions of approximately 110,000 tpy of over 40 HAP (including benzene, toluene, ethylbenzene, xylenes, and formaldehyde) from the Oil and Natural Gas Industry. Table 12 gives the risk and demographic results for the Oil and Natural Gas Industry from this screening-level assessment. We estimate there are 39,000 people with cancer risk greater than or equal to 100-in-1 million attributable to oil and natural gas sources, with a maximum estimated risk of 200-in-1 million occurring in three census blocks (10 people). We estimate there are about 143,000 people with estimated risk greater than or equal to 50-in-1 million, and about 6.8 million people with estimated cancer risk greater than 1-in-1 million. It is important to note that these estimates are subject to various types of uncertainty related to input parameters and assumptions, including emissions datasets, exposure modeling and the dose-response relationships. ¹³⁷

¹³⁷  See `Risk Report Template' at Docket ID No. EPA-HQ-OAR-2021-0317.

As shown in Table 12, Hispanic and Latino populations and young people (ages 0-17) are disproportionately represented in communities exposed to elevated cancer risks from oil and natural gas sources, while the proportion of people in other demographic groups with estimated risks above the specified levels is at or below the national average. The overall percent minority is about the same as the national average, but the percentage of people exposed to cancer risks greater than or equal to the 100-in-1 million and 50-in-1 million thresholds who are Hispanic or Latino is about 10 percentage points higher than the national average. The overall minority percentage is not elevated compared to the national average because the African-American percentage is much lower than the national average. The demographic group of people aged 0-17 is slightly higher than the national average.

For criteria pollutants, we assessed exposures to ozone from Oil and Natural Gas Industry VOC emissions across races/ethnicities, ages, and sexes in a recent baseline (pre-control) air quality scenario. Annual air quality was simulated using a photochemical model for the year 2017, based on emissions from the most recent NEI. The analysis shows that the distribution of exposures for all demographic groups except Hispanic and Asian populations are similar to or below the national average or a reference population. Differences between exposures in Hispanic and Asian populations versus White or all populations are modest, and the results are subject to various types of uncertainty related to input parameters and assumptions.

In addition to climate and air quality impacts, the EPA also conducted analyses to characterize potential impacts on domestic oil and natural gas production and prices and to describe the baseline distribution of employment and energy burdens. Section XVI.d describes the results for our analysis of prices and production. For the distribution of baseline employment, we assessed the demographic characteristics of (1) workers in the oil and gas sector and (2) people living in oil and natural gas intensive communities. ¹³⁸ Comparing workers in the oil and natural gas sector to workers in other sectors, oil and natural gas workers may have higher than average incomes, be more likely to have completed high school, and be disproportionately Hispanic. People in some oil and gas intensive communities concentrated in Texas, Oklahoma, and Louisiana have lower average income levels, lower rates of high school completion, and higher likelihood of being non-Whites or hispanic than people living in communities that are not oil and gas intensive. Regarding household energy burden, low-income households, Hispanic, and Black households' energy expenditures may comprise a disproportionate share of their total expenditures and income as compared to higher income, non-Hispanic, and non-Black households, respectively. Results are presented in detail in the RIA accompanying this proposal.

¹³⁸  For this analysis, oil and natural gas intensive communities are defined as the top 20% of communities with respect to the proportion of oil and natural gas workers.

In a proximity analysis of Tribes living within 50 miles of affected sources, we found 112 unique Tribal lands (Federally recognized Reservations, Off-Reservation Trust Lands, and Census Oklahoma Tribal Statistical Areas (OTSA)) located within 50 miles of a source with 32 Tribes having one or more sources located on Tribal land.

Finally, the EPA has also analyzed prior enforcement actions related to air pollution from storage vessels, and identified improvements in air quality resulting from these actions as particularly important in communities with EJ concerns (identified using EJSCREEN). ¹³⁹ In a 2021 analysis of resolved enforcement matters, the EPA determined that communities with EJ concerns experience a disproportionate level of air pollution burden from storage vessel emissions. Although only about 25 percent of storage vessels were located in these communities with EJ concerns, 67 percent of the total emission reductions of VOCs, methane, PM, and NO _X (about 95 million pounds) achieved through these enforcement resolutions occurred in communities with EJ concerns. This analysis suggests that the provisions of this proposed rule requiring installation of controls at storage vessels and monitoring and mitigation of fugitive emissions and malfunctions at storage vessels, would have particular benefits for these communities.

¹³⁹  See Memorandum “Analysis of Environmental Justice Impacts of EPA's Historical Oil and Gas Storage Vessel Enforcement Resolutions (40 CFR part 60 subpart OOOO and OOOOa),” located at Docket ID No. EPA-HQ-OAR-2021-0317.

C. Outreach and Engagement

The EPA identified stakeholder groups likely to be interested in this action and engaged with them in several ways including through meetings, training webinars, and public listening sessions to share information with stakeholders about this action, on how stakeholders may comment on the proposed rule, and to hear their input about the industry and its impacts as we were developing this proposal. Specifically, on May 27, 2021, the EPA held a webinar-based training designed for communities affected by this rule. ¹⁴⁰ This training provided an overview of the Crude Oil and Natural Gas Industry and how it is regulated and offered information on how to participate in the rulemaking process. The EPA also held virtual public listening sessions June 15 through June 17, 2021, and heard various community and health related themes from speakers who participated. ^{141   142} Community themes included concerns about protecting communities adjacent to oil and gas activities, providing monitoring and data so communities know what is in the air they are breathing, and upholding Tribal trust responsibilities. Community speakers urged the EPA to adopt stringent measures to reduce oil and natural gas pollution, and frequently cited an analysis suggesting such measures could achieve reductions of 65 percent below 2012 levels by 2025.

¹⁴⁰   https://www.epa.gov/sites/default/files/2021-05/documents/us_epa_training_webinar_on_oil_and_natural_gas_for_communities.5.27.2021.pdf .

¹⁴¹  June 15, 2021 session: https://youtu.be/T8XwDbf-B8g ; June 16, 2021 session: https://www.youtube.com/watch?v=l23bKPF-5oc ; June 17, 2021 session: https://www.youtube.com/watch?v=R2AZrmfuAXQ .

¹⁴²  Full transcripts for the listening sessions are posted at EPA Docket ID No. EPA-HQ-OAR-2021-0295.

Community Access to Emissions Information. Several stakeholders requested that the rule include requirements that provide communities with information, including fence line monitoring or “better monitoring so people will know the air they are breathing.” A few speakers expressed concerned about the correct placement of existing air monitors. Speakers from Texas described local air monitors monitoring meteorology and ozone, but not hazardous air pollutants, and called on the EPA to consider alternative monitoring for oil and natural gas sources such as fence-line monitors, along with guidance from the EPA to require monitors of oil and natural gas facilities in close proximity to parks, schools, and playgrounds.

Health Concerns in Adjacent Communities. Speakers raised concerns about impacts on frontline communities and those communities adjacent to oil and natural gas operations. These stakeholders called on the EPA to propose and promulgate stricter standards or alternative requirements for sources adjacent to urban communities and close to where people live and work. Several speakers used the term “energy sacrifice zone” when discussing the disproportionate impacts of oil and natural gas operations on frontline communities. Speakers advocated that when developing this regulatory effort, consultation with frontline communities is essential, and some speakers cited a Center for Investigative Reporting report stating that 30,000 children in Arlington, Texas, attend school within half a mile of active oil and gas sites. Speakers discussed concerns about methane as a formaldehyde precursor and related health effects and cited examples of health effects including hydraulic fracturing chemicals being measured in blood or urine; increases in nosebleeds in people in areas of oil and natural gas development; headaches and cancer. These speakers included teenagers from Pennsylvania, who said they live within 1 mile of 33 wellheads and 500 feet of a pipeline. Several people cited a February 2018 blowout and explosion in Belmont County, Ohio, that was reported to release 60,000 tons of methane in 20 days and said that is more than some countries emit in a year. Speakers also expressed related environmental concerns such as water contamination and fresh drinking water being diverted for hydraulic fracturing. One speaker urged that information on local water use be provided in languages other than English, stating that in Big Spring (Howard County), Texas, the local government only provided information to use tap water “at your own risk” in English.

Additional concerns raised by communities included: Local compressor stations having numerous planned and unplanned releases into adjacent communities, which appear to be during startup; whether the EPA will use a robust cost analysis to address the economic impacts of labor loss and gas costs resulting from any regulation; if plugged and abandoned wells included in this action, will this regulation apply to BLM land; will States be required to use the same emissions calculation used by the EPA for methane GWP; will there be disclosure of necessary data collection or technology to be used by the Oil and Natural Gas Industry to track and reduce methane emissions; and will the EPA consider the necessity of venting and flaring from a safety standpoint. Communities also discussed concerns about excess emissions from storage vessels and the need for clarifying the applicability of the standard in addition to improving enforceability and compliance at this type of facility.

In addition to the trainings and listening sessions, the EPA engaged with community leaders potentially impacted by this proposed action by hosting a meeting with EJ community leaders on May 14, 2021. As noted above, the EPA provided the public with factual information to help them understand the issues addressed by this action. We obtained input from the public, including communities, about their concerns about air pollution from the oil and gas industry, including receiving stakeholder perspectives on alternatives. The EPA considered and weighed information from communities as the agency developed this proposed action.

In addition to the engagement conducted prior to this proposal, the EPA is providing the public, including those communities disproportionately impacted by the burdens of pollution, opportunities to engage in the EPA's public comment period for this proposal, including by hosting public hearings. This public hearing will occur according to the schedule identified in the DATES and SUPPLEMENTARY INFORMATION section of this preamble to discuss:

• What impacts they are experiencing ( i.e., health, noise, smells, economic),

• How the community would like the EPA to address their concerns,

• How the EPA is addressing those concerns in the rulemaking, and

• Any other topics, issues, concerns, etc. that the public may have regarding this proposal.

For more information about the EPA's pre-proposal outreach activities, please see EPA Docket ID No. EPA-HQ-OAR-2021-0295. Please refer to EPA Docket ID No. EPA-HQ-OAR-2021-0317 for submitting public comments on this proposed rulemaking. For public input to be considered during the formal rulemaking, please submit comments on this proposed action to the formal regulatory docket at EPA Docket ID No. EPA-HQ-OAR-2021-0317 so that the EPA may consider those comments during the development of the final rule.

D. Environmental Justice Considerations

The EPA considered EJ implications in the development of this proposed rulemaking process, including the fair treatment and meaningful involvement of all people regardless of race, color, national origin, or income. As part of this process, the EPA engaged and consulted with frontline communities through interactions such as webinars, listening sessions and meetings. These opportunities gave the EPA a chance to hear directly from the public, especially overburdened and underserved communities, on the development of the proposed rule. The EPA considered these community concerns throughout our internal development process that resulted in this proposal which, if finalized in a manner similar to what is being proposed, will reduce emissions of harmful air pollutants, promote gas capture and beneficial use, and provide opportunity for flexibility and expanded transparency in order to yield a consistent and accountable national program. The EPA's proposed NSPS and EG are summarized in sections XI and XII below. Anticipated impacts of this action are discussed further in section XVI of this preamble.

In recognizing that minority and low-income populations often bear an unequal burden of environmental harms and risks, the EPA continues to consider ways to protect them from adverse public health and environmental effects of air pollution emitted from sources within the Oil and Natural Gas Industry that are addressed in this proposed rulemaking. For these reasons, in section XIV.C the EPA is proposing to include an additional requirement associated with the adoption and submittal of State plans pursuant to EG OOOOc (in addition to the current requirements of Subpart Ba) by requiring States to meaningfully engage with members of the public, including overburdened and underserved communities, during the plan development process and prior to adoption and submission of the plan to the EPA. The EPA is proposing this specific meaningful engagement requirement to ensure that the State plan development process is inclusive, effective, and accessible to all.

Details of the EPA's assessment of EJ considerations can be found in the RIA for this action. The EPA seeks input on the EJ analyses contained in the RIA, as well as broader input on other health and environmental risks the Agency should assess in the comprehensive development of this proposed action. In particular, the EPA is soliciting comment on key assumptions underlying the EJ analysis as well as data and information that would enable the Agency to conduct a more nuanced analysis of HAP and criteria pollutant exposure and risk, given the inherent uncertainty regarding risk assessment. More broadly, the EPA seeks information, analysis, and comment on how the provisions of this proposed action would affect air pollution and health in communities with environmental justice concerns, and whether there are further provisions that EPA should consider as part of a supplemental proposal or a final rule that would enhance the health and environmental benefits of this rule for these communities.

VII. Other Stakeholder Outreach

A. Educating the Public, Listening Sessions, and Stakeholder Outreach

The EPA began the development of this proposed action to reduce methane and other harmful pollutants from new and existing sources in the Crude Oil and Natural Gas source category with a public outreach effort to gather a broad range of stakeholder input. This effort included: Opening a public docket for pre-proposal input;  ¹⁴³ holding training sessions providing overviews of the industry, the EPA's rulemaking process and how to participate in it; and convening listening sessions for the public, including a wide range of stakeholders. The EPA additionally held roundtables with State environmental commissioners through the Environmental Council of the States, and oil and gas commissioners and staff through the Interstate Oil and Gas Compact Commission (IOGCC), and met with non-governmental organizations (NGOs), industry, and the U.S. Climate Alliance, among others. ¹⁴⁴

¹⁴³  EPA Docket ID No. EPA-HQ-OAR-2021-0295.

¹⁴⁴  A full list of pre-proposal meetings the EPA participated in is included at EPA Docket ID No. EPA-HQ-OAR-2021-0317.

In addition to the trainings and listening sessions noted in section VI above, on May 25 and 26, 2021, the EPA held webinar-based trainings designed for small business stakeholders  ¹⁴⁵ and Tribal nations. ¹⁴⁶ The training provided an overview of the Oil and Natural Gas Industry and how it is regulated and offered information on how to participate in the rulemaking process. A combined total of more than 100 small business stakeholders and Tribal nations participated. During the training, small business stakeholders expressed interest in learning more about the EPA's plan to either modify the 2016 NSPS OOOOa or take more substantial action in this proposal. For Tribal nations, the EPA has assessed potential impacts on Tribal nations and populations and has engaged with Tribal stakeholders to hear concerns associated with air pollution emitted from sources within the Oil and Natural Gas Industry that are addressed in this proposed rulemaking. Tribal members mentioned the need for the EPA to uphold its trust responsibilities, propose and promulgate rules that protect disproportionately impacted communities, and asked that the EPA allocate resources for Tribal governments to implement regulations through Tribal air quality programs.

¹⁴⁵   https://www.epa.gov/sites/default/files/2021-05/documents/oil_and_gas_training_webinar_small_businesses_05.25.21.pdf.

¹⁴⁶   https://www.epa.gov/sites/default/files/2021-05/documents/usepa_training_webinar_on_oil_and_natural_gas_for_tribes.5.26.2021.pdf.

As noted above, the EPA also heard from a broad range of stakeholders during virtual public listening sessions held from June 15 through June 17, 2021, ¹⁴⁷ which featured a total of 173 speakers. ¹⁴⁸ Many speakers stressed the urgent need to address climate change and the importance of reducing methane pollution as part of the nation's overall response to climate change. In addition to the community perspectives described above, the Agency also heard from industry speakers who were generally supportive of the regulation and stressed the need to provide compliance flexibility and allow industry the ability to use cutting-edge tools, including measurement tools, to implement requirements. Technical comments from other speakers also focused on a need for robust methane monitoring and fugitive emissions monitoring, a need to strengthen standards for flares as a control for associated gas, and suggestions to improve compliance. The sections below provide additional details on the information presented by stakeholders during these listening sessions.

¹⁴⁷  June 15, 2021 session: https://youtu.be/T8XwDbf-B8g; June 16, 2021 session: https://www.youtube.com/watch?v=l23bKPF-5oc; June 17, 2021 session: https://www.youtube.com/watch?v=R2AZrmfuAXQ.

¹⁴⁸  Full transcripts for the listening sessions are posted in at EPA Docket ID No. EPA-HQ-OAR-2021-0295.

1. Technical Themes

Measurement and Monitoring. Stakeholders advocated that the EPA modernize the rule by employing next-generation tools for methane identification and quantification, particularly for large emission or “super-emissions” events. Stakeholders particularly focused on allowing the use of remote sensing to help industry more easily comply with monitoring requirements at well pads, which are numerous and geographically spread out in some States. Stakeholders specified the desire to use innovative remote sensing technologies to monitor fugitive emissions and large emission events, including aerial, truck-based, satellite, and continuous monitoring. Several speakers focused on the need for regular monitoring, repair, and reporting, including ambient air monitoring in oil and natural gas development areas, as well as suggesting that the EPA pursue more robust methane monitoring for fugitive emissions, ensure that repair is completed, and pursue robust monitoring and reporting to verify the efficacy of the regulations.

Implementation, Compliance, and Enforcement. Numerous stakeholders raised concerns about flaring of associated gas and advocated for more stringent standards to ensure that flares used as control devices perform effectively. One speaker, an OGI expert, noted seeing many flares that were not operating the way they were intended to and that were not adequately designed ( e.g., unlit flares and ignition gas not being close enough to the waste gas stream to properly ignite). The speaker suggested that the EPA consider the concept of `thermal tuning' of flares by using OGI to see if a plume of unburned hydrocarbons extends downwind from the flare, to ensure that flares are actually operating effectively; the speaker suggested that this use of OGI could be done in conjunction with fugitive emissions monitoring to make sure controls are working. Stakeholders further emphasized the need for recordkeeping of any inspections that are made ( e.g., looking for flare damage from burned tips, lightning strikes). Some stakeholders also requested that the EPA consider reducing or eliminating flaring of associated gas and incentivizing capture. Lastly, one speaker raised concerns about flaring of associated gas in Texas and how flaring is permitted by the State. In response to these concerns, the EPA is proposing to reduce venting and flaring of associated gas and to require monitoring of flares to detect malfunctions. Further, the EPA is soliciting comment on whether to adopt additional measures to assure proper design and operation of control devices, including flares, as discussed in section XIII.

Stakeholders raised other implementation, compliance, and enforcement concerns, including calls for the EPA to develop rules that are easy to apply and implement given States' limited budgets. Stakeholders cautioned that “flexibility” in a rule can be interpreted as a “loophole,” and opined that a rule that sets clear and uniform expectations will help avoid confusion. At the same time, speakers stated that a “prescriptive checklist” does not work in today's environment and recommended that the EPA modernize the regulatory approach. Several speakers, including speakers from Texas and North Dakota, raised concerns about the limited enforcement capacity of local and State governments, as well as the EPA and its regional officials and stated that this may result in implementation gaps. Speakers called on the EPA to have a third-party verification or audit requirements for fugitive emissions and cited to Texas's requirement for third-party audits to evaluate operator LDAR programs for highly reactive VOC. Speakers also cited to the public-facing Environmental Defense Fund (EDF) methane map  ¹⁴⁹ with geotags of sources with observed hydrocarbon emissions, which provides operators an opportunity to respond to posted leak videos and measurements. Lastly, one speaker requested that the EPA not allow exemptions for start-up and shutdown emissions events. The EPA is soliciting comment on ways to utilize credible emissions information obtained from communities and others, as discussed in section XI.A.1.

¹⁴⁹   https://www.permianmap.org.

Wells and Storage. Some stakeholders requested that the EPA consider a program for capping abandoned wells to ensure those wells are properly closed and not leaking. Speakers called on the EPA to consider abandoned and unplugged wells in the context of EJ communities adjacent to affected facilities and requested that the EPA incentivize appropriate well closure. In response to this input and to gather information that will be needed to inform possible future actions, the EPA is soliciting comment on ways to address abandoned wells, including potential closure requirements. See section XIII.B. Stakeholders also focused on marginal wells and asked that the EPA consider system-wide reductions be allowed, for example, at the basin level, and expressed challenges of retrofitting existing well sites and low production well sites where addition of control devices or closed vent systems would be necessary. Some speakers raised concern about ensuring that facilities are engineered for the basin or target formation from which they produce.

Job Creation. Some speakers stated that this rulemaking is a job creation rule and encouraged a “next generation” approach to methane standards, such as incentivizing continuous monitoring. Other speakers cited a study about job creation in the methane mitigation industry. ¹⁵⁰

¹⁵⁰  Stakeholders submitted the following studies to the pre-proposal docket: https://www.regulations.gov/comment/EPA-HQ-OAR-2021-0295-0016 and https://www.regulations.gov/comment/EPA-HQ-OAR-2021-0295-0017.

Inventory, Loss Rates, and Methane Global Warming Potential. Several speakers criticized the EPA's emission inventories stating that the EPA is not using the correct data in its inventory, that the GHGI data is inaccurate because it relies on facility reporting of emissions from calculations and estimation methods rather than measurement and monitoring, and suggested that the EPA rely on monitoring and measurement of actual emissions and subsequently make the monitoring data publicly available. Speakers raised issues with differences in inventories across Federal agencies, contrasting DOE's Environmental Impact Statements and EPA's NEI. Stakeholders suggested that the EPA use data collected by EDF and other researchers, which calculated methane emissions to be 60 percent higher than the EPA's estimates. ¹⁵¹ Speakers also mentioned the amount of methane that is lost from wells each year, providing varying estimates of these emissions. Lastly, stakeholders called on the EPA to use the 20-year GWP for methane, instead of the 100-year value the agency uses.

¹⁵¹  Alvarez et al. 2018. Assessment of methane emissions from the U.S. oil and gas supply chain. Science 13 Jul 2018: Vol. 361, Issue 6398, pp. 186-188.

2. Climate and Other Themes

Several speakers mentioned the effects of climate change from oil and natural gas methane emissions, such as impacts on farmland, wildfires, and transmission of tick-borne pathogens. Many speakers pointed out the extreme heat and drought that currently are affecting the western U.S. Stakeholders asked that the EPA examine the impacts of the Oil and Natural Gas Industry on small businesses that are not part of the regulated community, such as businesses that rely on outdoor recreation or water flow that could be affected by oil and natural gas operations. A speaker raised concerns about the impact of the industry on tourism, saying that 30 percent of their local economy relies on tourism and outdoor recreation. Lastly, a speaker discussed pipeline weatherization needs and suggested that the EPA and other Federal agencies account for seasonal variability.

In addition to the public listening sessions, on June 29, 2021, the EPA met with environmental commissioners and staff through the Environmental Council of the States (ECOS). Subsequently, on July 12, 2021, the EPA participated in a roundtable with members of the IOGCC. The discussions in both roundtables included air emissions monitoring technologies and interactions between the EPA's requirements and State rules. For the ECOS roundtable, the EPA also sought feedback on and implementation of the EPA's current NSPS; for the IOGCC roundtable, the EPA also requested feedback on compliance with the rules.

Key themes from both roundtables included the following: Allowing for the use of broad types of methane detection technologies; improving and streamlining the EPA's AMEL process, such as by structuring it so it could apply broadly rather than on a site-by-site basis; requests that expanded aspects of States' rules be deemed equivalent to the EPA's rule, and requests that the EPA's rule complement State regulations in a way that would not interrupt the work of State agencies requiring them to request State legislative approvals. Other common themes were requests that the rule provide flexibility and be easy to implement, particularly for marginal or low production wells owned by independent small businesses, and that the EPA coordinate its rules with those of other Federal agencies, notably the DOI's BLM.

Other input included the need to fill gaps by addressing additional opportunities to reduce emissions beyond the 2016 NSPS OOOOa, concerns about the complexity of the calculation for the potential to emit for storage vessels, a desire that the EPA's rule not slow momentum of voluntary efforts to reduce emissions, and a desire for regulations that recognize geographic differences.

B. EPA Methane Detection Technology Workshop

The EPA held a virtual public workshop on August 23 and 24, 2021, to hear perspectives on innovative technologies that could be used to detect methane emissions from the Oil and Natural Gas Industry. ¹⁵² The workshop focused on methane-sensing technologies that are not currently approved for use in the NSPS for the Oil and Natural Gas Industry, and how those technologies could be applied in the Crude Oil and Natural Gas sector. Panelists provided twenty-four live presentations during the workshop. The panelists all had firsthand experience evaluating innovative methane-sensing technologies or had used these technologies to identify methane emissions and presented about their experience. The live presentations were broken into six panel sessions, each focused on a particular topic, e.g., satellite measurements, methane sensors, aerial technologies. At the end of each panel session, the set of panelists participated in a question-and-answer session. In addition to the live presentations, the workshop included a virtual exhibit hall for technology vendors to provide video presentations on their innovative technologies, with a focus on technology capability, applicability, and data quality. Forty-two vendors participated in the virtual vendor hall.

¹⁵²   https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry/epa-methane-detection-technology-workshop.

Nine hundred sixty stakeholders registered to participate in the workshop. The workshop was also livestreamed, so stakeholders who could not attend could watch the recorded livestream later at their convenience. The registrants included a wide range of stakeholders including, academics, methane detection technology end-user and vendors, governmental employees (local, State, and Federal), and NGOs.

C. How is this information being considered in this proposal?

The EPA's pre-proposal outreach effort was intended to gather stakeholder input to assist the Agency with developing this proposal. ¹⁵³ The EPA recognizes that tackling the dangers of climate change will require an “all-hands-on deck” approach through regulatory, voluntary, and community programs and initiatives. Throughout the development of this proposed rule, the EPA considered the stakeholders' experiences and lessons learned to help inform how to better structure this proposal and consider ongoing challenges that will require continued collaboration with stakeholders. The EPA will continue to consider the information obtained in developing this proposal as we take the next steps on the proposed regulations.

¹⁵³  The EPA opened a non-regulatory docket for stakeholder to submit early input. That early input can be found at EPA Docket I.D. Number EPA-HQ-OAR-2021-0295.

With this proposal, the EPA seeks further input from the public and from all stakeholders affected by this rule. Throughout this action, unless noted otherwise, the EPA is requesting comments on all aspects of this proposal, including on several themes raised in the pre-proposal outreach ( e.g., innovative technologies for methane detection and quantification). Please see section XI.A.1 of this preamble for specific solicitations for comment regarding advanced measurement technologies and section XIII for solicitations for comments on additional emission sources. For public input to be considered on this proposal, ¹⁵⁴ please submit comments on this proposed action to the regulatory docket at EPA Docket ID No. EPA-HQ-OAR-2021-0317 so that the EPA may consider those comments during the development of the final rule.

¹⁵⁴  Information submitted to the pre-proposal non-regulatory docket at Docket ID No. EPA-HQ-OAR-2021-0295 is not automatically part of the proposal record. For information and materials to be considered in the proposed rulemaking record, it must be resubmitted in the rulemaking docket at EPA Docket ID No. EPA-HQ-OAR-2021-0317.

VIII. Legal Basis for Proposal Scope

The EPA proposes in this rulemaking to revise certain NSPS and to promulgate additional NSPS for both methane and VOC emissions from new oil and gas sources in the production, processing, 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 immediate regulatory action. This section explains EPA's legal justification for proceeding with this proposed action, including regulating methane and VOCs from sources in all segments of the source category. The EPA first describes the history of our regulatory actions for oil and gas sources in 2016 and 2020—including the key legal interpretations and factual determinations made—as well as Congress's action in 2021 in response. The EPA then explains the implications of Congress's action and why we would come to the same conclusion even if Congress had not acted.

This proposal is in line with our 2016 NSPS OOOOa rule, which likewise regulated methane and VOCs from all three segments of the industry. The 2016 NSPS OOOOa rule explained that these three segments should be regulated as part of the same source category because they are an interrelated sequence of functions in which pollution is produced from the same types of sources that can be controlled by the same techniques and technologies. That rule further explained that the large amount of methane emissions, coupled with the adverse effects of GHG air pollution, met the applicable statutory standard for regulating methane emissions from new sources through NSPS. Furthermore, the rule explained, this regulation of methane emissions from new sources triggered the EPA's authority and obligation to set guidelines for States to develop standards to regulate the overwhelming majority of oil and gas sources, which the CAA categorizes as “existing” sources. In the 2020 Policy Rule, the Agency reversed course, concluding based upon new legal interpretations that the rule concluded the EPA had not made the proper determinations necessary to issue such regulations. This action eliminated the Agency's authority and obligation to issue EG for existing sources. In 2021, Congress adopted a joint resolution to disapprove the EPA's 2020 Policy Rule under the CRA. According to the terms of CRA, the 2020 Policy Rule is “treated as though [it] had never taken effect,” 5 U.S.C. 801(f), and as a result, the 2016 Rule is reinstated.

In disapproving the 2020 Policy Rule under the CRA, Congress explicitly rejected the 2020 Policy Rule interpretations and embraced EPA's rationales for the 2016 NSPS OOOOa rule. The House Committee on Energy & Commerce emphasized in its report that the source category “is the largest industrial emitter of methane in the U.S.,” and directed that “regulation of emissions from new and existing oil and gas sources, including those located in the production, processing, and transmission and storage segments, is necessary to protect human health and welfare, including through combatting climate change, and to promote environmental justice.” H.R. Rep. No. 117-64, 3-5 (2021) (House Report). A statement from the Senate cosponsors likewise underscored that “methane is a leading contributing cause of climate change,” whose “emissions come from all segments of the Oil and Gas Industry,” and stated that “we encourage EPA to strengthen the standards we reinstate and aggressively regulate methane and other pollution emissions from new, modified, and existing sources throughout the production, processing, transmission and storage segments of the Oil and Gas Industry under section 111 of the CAA.” 167 Cong. Rec. S2282 (April 28, 2021) (statement by Sen. Heinrich) (Senate Statement). ¹⁵⁵ The Senators concluded with a stark statement: “The welfare of our planet and of our communities depends on it.” Id. at S2283.

¹⁵⁵  Sen. Heinrich stated that he made this statement on behalf of “[Majority [l]eader Chuck Schumer, Chairman Tom Carper of the Committee on Environment and Public Works, Senator Angus King, Senator Edward Markey and [himself],” who he described as “leading supporters and sponsors of S.J. Res. 14. . . .” Senate Statement at S. 2282. Thus, the Senate Statement should be considered an authoritative piece of the legislative history. It should be noted that the Joint Resolution was referred to the Senate Committee on Environment and Public Works and discharged from the committee by petition pursuant to 5 U.S.C. 802(c), https://www.congress.gov/bill/117th-congress/senate-joint-resolution/14/all-actions. As a result, the resolution was not accompanied by a report from the Senate committee.

This proposal comports with the EPA's CAA section 111 obligation to reduce dangerous pollution and responds to the urgency expressed by the current Congress. With this proposal, the EPA is taking additional steps in the regulation of the Crude Oil and Natural Gas source category to protect human health and the environment. Specifically, the agency is proposing to revise certain of those NSPS, to add NSPS for additional sources, and to propose EG that, if finalized, would impose a requirement on States to regulate methane emissions from existing sources. As the EPA explained in the 2016 Rule, this source category collectively emits massive quantities of the methane emissions that are among those driving the grave and growing threat of climate change, particularly in the near term. 81 FR 35834, June 3, 2016. As discussed in section III above, since that time, the science has repeatedly confirmed that climate change is already causing dire health, environmental, and economic impacts in communities across the United States.

Because the 2021 CRA resolution automatically reinstated the 2016 Rule, which itself determined that the Crude Oil and Natural Gas Source Category included the transmission and storage segment and that regulation of methane emissions was justified, the EPA is authorized to take the regulatory actions proposed in this rule. As explained below, we are reaffirming those determinations as clearly authorized under any reasonable interpretation of section 111. Because the reinstatement of the 2016 Rule provides the only necessary predicate for this rule, and because, as described, the interpretations underlying this rule are sound, the EPA is not reopening them here.

A. Recent History of the EPA's Regulation of Oil and Gas Sources and Congress's Response

1. 2016 NSPS OOOOa Rule

As described above, the 2016 NSPS OOOOa rule extended the NSPS for VOCs for new sources in the Crude Oil and Natural Gas source category and also promulgated NSPS for methane emissions from new sources. This rule contained several interpretations that were the bases for these actions, and that are important for present purposes. First, the EPA confirmed its position in the 2012 NSPS OOOO rule that the scope of the oil and gas source category included the transmission and storage segment, in addition to the production and processing segments that the EPA had regulated since 1984. The agency stated that it believed these segments were included in the initial listing of the source category, and to the extent they were not, the agency determined to add them as appropriately encompassed within the regulated source category. The EPA based this latter conclusion on the structure of the industry. In particular, the EPA emphasized that “[o]perations at production, processing, transmission, and storage facilities are a sequence of functions that are interrelated and necessary for getting the recovered gas ready for distribution,” and further explained, “[b]ecause they are interrelated, segments that follow others are faced with increases in throughput caused by growth in throughput of the segments preceding ( i.e., feeding) them.” 81 FR 35832, June 3, 2016. The EPA also recognized “that some equipment ( e.g., storage vessels, pneumatic pumps and compressors) are used across the oil and natural gas industry.” Id. Having made clear that the Crude Oil and Natural Gas source category includes the transmission and storage segment, the EPA proceeded to promulgate NSPS for sources in that segment. Id. at 35826.

Second, in promulgating NSPS for methane emissions for new sources in the source category, the EPA explained its decision to regulate GHGs for the first time from the source category. Noting that the plain language of CAA section 111 requires a significant-contribution analysis only when EPA regulates a new source category, not a new pollutant, the Agency stated that it “interprets CAA section 111(b)(1)(B) to provide authority to establish a standard for performance for any pollutant emitted by that source category as long as the EPA has a rational basis for setting a standard for the pollutant.” 81 FR 35842, June 3, 2016. In the alternative, if a rational-basis analysis were deemed insufficient, the EPA explained that it also concluded that GHG emissions, in the form of methane emissions, from the regulated Crude Oil and Natural Gas source category significantly contribute to dangerous pollution. Id. at 81 FR 35843, and 35877. In making the rational basis and alternative significant contribution findings, the EPA focused on “the high quantities of methane emissions from the Crude Oil and Natural Gas source category.” Id. The EPA emphasized, among other things, that “[t]he Oil and Natural Gas source category is the largest emitter of methane in the U.S., contributing about 29 percent of total U.S. methane emissions.” Id. The EPA added that “[t]he methane that this source category emits accounts for 3 percent of all U.S. GHG emissions . . . [and] GWP-weighted emissions of methane from these sources are larger than emissions of all GHGs from about 150 countries.” Id. The EPA concluded that “the[se] facts . . . along with prior EPA analysis” concerning the effect of GHG air pollution on public health and welfare, “including that found in the 2009 Endangerment Finding, provide a rational basis for regulating GHG emissions from affected oil and gas sources . . .” as well as for concluding in the alternative that oil and gas methane significantly contributes to dangerous pollution. Id. at 35843.

In addition, in the 2016 NSPS OOOOa Rule, EPA recognized that promulgation of NSPS for methane emissions under section 111(b)(1)(B) triggered the requirement that EPA promulgate EG to require States to regulate methane emissions from existing sources under section 111(d)(1), and described the steps it was taking to lay the groundwork for that regulation. 81 FR at 35831.

2. 2020 Policy Rule

The 2020 Policy Rule rescinded key elements of the 2016 NSPS OOOOa rule based on different factual assertions and statutory interpretations than in the 2016 Rule. Specifically, the 2020 Policy Rule stated that it “contains two main actions,” 85 FR 57019, September 14, 2020 which it identified as follows: “First, the EPA is finalizing a determination that the source category includes only the production and processing segments of the industry and is rescinding the standards applicable to the transmission and storage segment of the industry. . . .” Id. The rule justified this first action in part on the grounds that “the processes and operations found in the transmission and storage segment are distinct from those found in the production and processing segments,” because “the purposes of the operations are different” and because “the natural gas that enters the transmission and storage segment has different composition and characteristics than the natural gas that enters the production and processing segments.” Id. at 57028. “Second, the EPA is separately rescinding the methane requirements of the NSPS applicable to sources in the production and processing segments.” Id. EPA justified the rescission of the methane NSPS on two grounds. One was the EPA's “conclu[sion] that those methane requirements are redundant with the existing NSPS for VOC and, thus, establish no additional health protections.” Id. at 57019. The second was a statutory interpretation: the EPA rejected the rational basis interpretation of the 2016 Rule, and stated that instead, “[t]he EPA interprets [the relevant provisions in CAA section 111] . . . to require, or at least to authorize the Administrator to require, a pollutant-specific SCF as a predicate for promulgating a standard of performance for that air pollutant.” Id. at 57035. The rule went on to “determine that the SCF for methane that the EPA made in the alternative in the 2016 [NSPS OOOOa] Rule was invalid and did not meet this statutory standard,” for two reasons: (i) “[t]he EPA made that finding on the basis of methane emissions from the production, processing, and transmission and storage segments, instead of just the production and processing segments”; and (ii) “the EPA failed to support that finding with either established criteria or some type of reasonably explained and intelligible standard or threshold for determining when an air pollutant contributes significantly to dangerous air pollution.” Id. at 57019. The rule recognized that “by rescinding the applicability of the NSPS . . . to methane emissions for [oil and gas] sources . . . existing sources . . . will not be subject to regulation under CAA section 111(d).” Id. at 57040.

3. CRA Resolution Disapproving the 2020 Policy Rule and Reinstating the 2016 NSPS OOOOa Rule

On June 30, 2021, the President signed into law a joint resolution adopted by Congress under the CRA disapproving the 2020 Policy Rule. By the terms of the CRA, this 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, upon the disapproval, by operation of law, the 2016 NSPS OOOOa rule was reinstated, including the inclusion of the transmission and storage segment in the source category, the VOC NSPS for sources in that segment, and the methane NSPS for sources across the source category. And with the reinstatement of the methane NSPS, the EPA's obligation to issue EG to require States to regulate existing sources for methane emissions was reinstated as well. Moreover, the CRA bars an agency from promulgating “a new rule that is substantially the same as” a disapproved rule. 5 U.S.C. 801(b)(2).

The accompanying legislative history, specifically a House Committee report (H.R. Rep. 117-64) and a statement on the Senate floor by the sponsors of the CRA resolution (Senate Statement at S2282-83), provides additional specificity regarding Congress's intent in disapproving 2020 Policy Rule and reinstating the 2016 Rule with regard to the scope of the source category and the regulation of methane.

a. Regulation of Transmission and Storage Sources

The House Report rejected the 2020 Policy Rule's removal of the transmission and storage segment from the Crude Oil and Natural Gas Source Category, and its rescission of the VOC and methane NSPS promulgated in the 2012 NSPS OOOO and 2016 NSPS OOOOa rules for transmission and storage sources. House Report at 7; 85 FR 57029, September 14, 2020 (2020 Policy Rule). The Report recognized that in authorizing the EPA to list for regulation “categories of sources” under section 111(b)(1)(A) of the CAA, Congress “provided the EPA with wide latitude to determine the scope of a source category . . . and to expand the scope of an already-listed source category if the agency later determines that it is reasonable to do so.” House Report at 7. The Report stated that in the 2016 NSPS OOOOa, “EPA correctly determined that the equipment and operations at production, processing, and transmission and storage facilities are a sequence of functions that are interrelated and necessary for the overall purpose of extracting, processing, and transporting natural gas for distribution.” Id.; see 81 FR 35832, June 3, 2016 (2016 Rule). The Report added that the 2016 NSPS OOOOa also “correctly determined that the types of equipment used and the emissions profile of the natural gas in the transmission and storage segments do not so distinctly differ from the types of equipment used and the emissions profile of the natural gas in the production and processing segments as to require that the EPA create a separate source category listing.” House Report at 7; see 81 FR 35832, June 3, 2016. The Report went on to reject the 2020 Policy Rule's basis for excluding the transmission and storage segment, finding that the functions of the various segments in the Crude Oil and Natural Gas sector are all “interrelated and necessary for the overall purpose” of the industry, House Report at 7, and that EPA correctly determined in 2016 that the source types and emissions found in the transmission and storage segment are sufficiently similar to production and processing as to justify regulating these segments in a single source category. Id.

The Senate Statement was also explicit that the 2020 Policy Rule erred in rescinding NSPS for sources in the transmission and storage segment:

[T]he resolution clarifies our intent that EPA should regulate methane and other pollution emissions from all oil and gas sources, including production, processing, transmission, and storage segments under the authority of section 111 of the CAA. In addition, we intend that section 111 . . . obligates and provides EPA with the legal authority to regulate existing sources of methane emissions in all of these segments.

Senate Statement at S2283 (paragraphing revised).

b. Regulation of Methane—Redundancy

The House Report and Senate Statement made clear Congress's view that in light of the large amount of methane emissions from oil and gas sources and their impact on global climate, the EPA must regulate those emissions under section 111. House Report at 5; Senate Statement at S2283. Both pieces of legislative history specifically rejected the 2020 Policy Rule's rescission of the methane NSPS. House Report at 7; Senate Statement at S2283. Moreover, the legislative history specifically rejected the statutory interpretations of section 111 that formed the bases of EPA's 2020 rationales for rescinding the methane NSPS. House Report at 7-10; see Senate Statement at S2283; see 85 FR 57033, 57035-38 (September 14, 2020).

The House Report began by recognizing the critical importance of regulating methane emissions from oil and gas sources, emphasizing both the potency of methane in driving global warming, and the massive amounts of methane emitted each year by the oil and gas industry. House Report at 3-4. The House Report was clear that the amount of these emissions and their impact compelled regulatory action. Id. at 5. The Senate Statement was equally clear:

[M]ethane is a leading contributing cause of climate change. It is 28 to 36 times more powerful than carbon dioxide in raising the Earth's surface temperature when measured over a 100-year time scale and about 84 times more powerful when measured over a 20-year timeframe.

Industrial sources emit GHG in great quantities, and methane emissions from all segments of the Oil and Gas Industry are especially significant in their contribution to overall emissions levels and surface temperature rise. . . .

In fact, with the congressional adoption of this resolution, we encourage EPA to strengthen the standards we reinstate and aggressively regulate methane and other pollution emissions from new, modified, and existing sources throughout the production, processing, transmission, and storage segments of the Oil and Gas Industry under section 111 of the Clean Air Act.

The welfare of our planet and of our communities depend on it.

Senate Statement at S2283.

Turning to the 2020 Policy Rule, the House Report rejected the rule's position that the methane NSPS were redundant to the VOC NSPS, and therefore unnecessary. House Report at 7. The House Report rejected the 2020 Policy Rule's “redundancy” rationale, explaining that in the 2016 NSPS OOOOa, the EPA had consciously “formulated [the two sets of NSPS so as] to impose the same requirements for the same types of equipment,” and that the co-extensive nature of the NSPS mean that “sources could comply with them in an efficient manner,” not that the NSPS were redundant. Id. The House report further rejected the 2020 Policy Rule's assertion that it need not take into account the implications of regulating methane for existing sources, calling it a “fundamental misinterpretation of section 111, and the critical importance of section 111(d) in Congress [ sic: Congress's] scheme.” House Report at 8 & n. 27 (The EPA's 2020 “misinterpretation . . . was glaring and enormously consequential” because it precluded regulation of methane from existing sources). The House Report emphasized that “existing sources emit the vast majority of methane in the oil and gas sector,” id. and pointed out that while the 2016 NSPS “covered roughly 60,000 wells constructed since 2015[, t]here are more than 800,000 existing wells in operation. . . .” Id. n.28.

The Senate Statement also made clear that the resolution of disapproval “reaffirms that the CAA requires EPA to act to protect Americans from sources of . . . methane,” “reject[s] the [2020 Policy Rule's] misguided legal interpretations,” and “clarifies our intent that EPA should regulate methane . . . from all oil and gas sources. . . .” Senate Statement at 2283.

c. Regulation of Methane—Significant Contribution Finding

The legislative history was explicit that, contrary to the EPA's statutory interpretation in the 2020 Policy Rule, section 111 of the CAA, by its plain language, does not require, or authorize the EPA to require, as a prerequisite for promulgating NSPS for a particular air pollutant from a listed source category, a separate finding by the EPA that emissions of the pollutant from the source category contribute significantly to dangerous air pollution. House Report at 9-10; Senate Statement at S2283. The House Report rejected this interpretation. It made clear that instead, consistent with the EPA's statements in the 2016 NSPS OOOOa and the plain language of the CAA, section 111 requires that the agency must make a SCF only at “the first step of the process, the listing of the source category,” and further requires that this finding “must apply to the impact of the `category of sources' on `air pollution' ” as opposed to individual pollutants. House Report at 9. The House Report went on to explain that this provision “does not require the EPA to make a SCF for individual air pollutants emitted from the source category, nor does it even mention individual air pollutants,” id. at 9. The House Report went on to explain in some detail the meaning that the EPA should give to section 111, which, consistent with the 2016 Rule, is that section 111 authorizes the agency to promulgate NSPS for particular pollutants as long as it has a rational basis for doing so. House Report at 8-9. The report explained that after the EPA lists a source category for regulation under section 111(b)(1)(A), it is required to determine for which pollutants to promulgate NSPS, and this determination is subject to CAA section 307(d)(9)(A) (“In the case of review of any [EPA] action . . . to which [section 307(d)] applies, the court may reverse any such action found to be arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with law”). ¹⁵⁶ The Report further noted that the U.S. Supreme Court affirmed this interpretation in American Electric Power Co. Inc. v. Connecticut, 564 U.S. 410, 427 (2011) ( American Electric Power ) (“EPA may not decline to regulate carbon-dioxide emissions from powerplants if refusal to act would be ‘arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with law” (citing section 307(d)(9)(A)). The Report went on to note that the 2016 NSPS OOOOa had stated that the EPA was authorized to promulgate a NSPS for a particular pollutant if it had a “rational basis” for doing so, and the Report emphasized that this “rational basis” standard is “fully consistent with” the arbitrary and capricious standard under section 307(d)(9)(A) of the CAA. House Report at 9. ¹⁵⁷

¹⁵⁶  Section 307(d) applies to the promulgation of NSPS, under section 307(d)(1)(C).

¹⁵⁷  The House Report dismissed the 2020 Policy Rule's criticism of the rational basis test as unduly vague by noting that a court could enforce it. House Report at 11.

The House Report further explained that, in contrast, the 2020 Policy Rule's statutory interpretation of section 111 to require a pollutant-specific SCF as a predicate for promulgating NSPS was foreclosed by “the plain language of” section 111—noting that this interpretation ignored the distinction between the text of section 111 and that of other CAA provisions which do explicitly require a pollutant-specific cause-or-contribution finding. Id. at 10. Moreover, the Report added, “[g]iven that the statute is not ambiguous, the EPA cannot interpret section 111 to authorize the EPA to exercise discretion to require . . . a pollutant-specific SCF as a predicate for promulgating a [NSPS] for the pollutant.” Id. at 10. The Report went on to note several other supports for its statutory interpretation, including the legislative history of section 111. Id. at 10-11.

The Senate Statement took the same approach, stating: “we do not intend that section 111 of [the] CAA requires EPA to make a pollutant-specific significant contribution finding before regulating emissions of a new pollutant from a listed source category. . . .” Senate Statement at S2283. ¹⁵⁸

¹⁵⁸  Both the House Report and the Senate Statement recognized that EPA could, if it chose to, make a finding that a particular pollutant contributes significantly to dangerous air pollution, in order, for example, to inform the public about the risks of a pollutant. House Report at 10, Senate Statement at S2283. However, the House Report made clear that “it is the rational basis determination as to the risk a pollutant poses to endangerment of human health or welfare [and not any such SCF] that remains the statutory basis for the EPA's action.” House Report at 10.

The House Report also expressly disapproved of the 2020 Policy Rule's interpretation of section 111 to require that the SCF must be based on some “identif[ied] standard or established set of criteria,” and not the facts-and-circumstances approach that EPA has used in making that finding for the source category. House Report at 10-11; see 2020 Policy Rule at 57038. The Report stated, “[i]t is fully appropriate for 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 EPA must regulate under section 111.” House Report at 11.

Finally, in reinstating the methane regulations, the legislative history for the CRA resolution clearly expressed the intent that the EPA proceed with regulation of existing sources. The House Report was explicit in this regard, stating that “[p]assage of the resolution of disapproval indicates Congress' support and desire to immediately reinstate . . . EPA's statutory obligation to regulate existing oil and natural gas sources under [CAA] section 111(d).” House Report at 3; see id. at 11-12. The report added that upon enactment of the resolution of disapproval, “the Committee strongly encourages the EPA to take swift action to . . . fulfill its statutory obligation to issue existing source guidelines under [CAA] section 111(d).” Id. The Senate Statement was substantially similar. Senate Statement at S2283 (“By adopting this resolution of disapproval, it is our view that Congress reaffirms that the CAA requires EPA to act to protect Americans from sources of climate pollution like methane, which endangers the public's health and welfare. . . . [W]e intend that [CAA] section 111 . . . obligates and provides EPA with the legal authority to regulate existing sources of methane emissions in [the Crude Oil and Natural Gas source category].”).

B. Effect of Congress's Disapproval of the 2020 Policy Rule

Under the CRA, the disapproved 2020 Policy Rule is “treated as though [it] had never taken effect.” 5 U.S.C. 801(f). As a result, the preceding regulation, the 2016 NSPS OOOOa rule, was automatically reinstated, and treated as though it had never been revised by the 2020 Policy Rule. Moreover, the CRA bars EPA from promulgating “a new rule that is substantially the same as” a disapproved rule. 5 U.S.C. 801(b)(2), for example, a rule that deregulates methane emissions from the production and processing sectors or deregulates the transmission and storage sector entirely.

The legislative history of the CRA gives further content to Congress's disapproval and the bar on substantially similar rulemaking. The legislative history rejected the EPA's statutory interpretations of section 111 in the 2020 Policy Rule and endorsed the legal interpretations contained in the 2016 NSPS OOOOa rule. Specifically, Congress expressed its intent that the transmission and storage segment be included in the source category, that sources in that segment remain subject to NSPS, and that all oil and gas sources be subject to NSPS for methane emissions. ¹⁵⁹

¹⁵⁹  See generally “Federal-State Unemployment Compensation Program; Establishing Appropriate Occupations for Drug Testing of Unemployment Compensation Applicants Under the Middle-Class Tax Relief and Job Creation Act of 2012: Final Rule,” 84 FR 53037, 53083 (Oct. 4, 2019) (citing legislative history of CRA resolution disapproving prior rule in explaining scope of new rule).

The EPA is now proceeding to propose additional requirements to reduce emissions from oil and gas sources, consistent with the statutory factors the EPA is required to consider under section 111 and with section 111's overarching purpose of protecting against pollution that endangers health and welfare. While the reinstatement of the 2016 Rule through the CRA joint resolution of disapproval provides the predicate for this action, the EPA notes that, for the reasons discussed next, the EPA would reject the positions concerning legal interpretations taken in the 2020 Policy Rule and reaffirm the positions the Agency took in the 2016 Rule even absent the CRA resolution. The EPA provides this information for the purposes of informing the public and is not re-opening these positions for comment.

C. Affirming the Legal Interpretations in the 2016 NSPS OOOOa Rule

The Agency has reviewed all of the information and analyses in the 2016 NSPS OOOOa and 2020 Policy Rule, and fully reaffirms the positions it took in the 2016 Rule and rejects the positions taken in the 2020 Policy Rule. ¹⁶⁰ For this rulemaking, the EPA has reviewed its prior actions, along with newly available information, including recent information concerning the dangers posed by climate change and the impact of methane emissions, as described in section III above. Based on this review, the EPA affirms the statutory interpretations underlying the 2016 Rule and rejects the different interpretations informing the congressionally voided 2020 Policy Rule. This section explains the EPA's views. These views are confirmed by Congress's reasoning in the legislative history of the CRA resolution and so, for convenience, this section occasionally refers to that legislative history.

¹⁶⁰  Under F.C.C. v. Fox Television Stations, Inc., 556 U.S. 502 (2009), an agency may revise its policy, but must demonstrate that the new policy is permissible under the statute and is supported by good reasons, taking into account the record of the previous rule. To the extent that this standard applies in this action—where Congress has disapproved the 2020 Policy Rule—the EPA believes the explanations provided here satisfy the standard.

In particular, the EPA reaffirms that the Crude Oil and Natural Gas Source Category appropriately includes the transmission and storage segment, along with the production and processing segments. The EPA has broad discretion in determining the scope of the source category, and the 2016 Rule correctly identified the most important aspect of the industry, which is the interrelatedness of the segments and their common purpose in completing the multi-step process to prepare natural gas for marketing. 81 FR 35832, June 3, 2016. The 2020 Policy Rule's objection that the chemical composition of natural gas changes as it moves from the production and processing segments to the transmission and storage segment, 85 FR 57028, September 14, 2020, misses the mark because in every segment methane predominates and the refining of natural gas in the processing segment, which is what changes its chemical composition, is appropriately viewed simply as one of the steps in the marketing of the gas. Further, while it is true that some of the equipment in each segment differs from the equipment in the other segments, as the 2020 Policy Rule pointed out, 85 FR 57029 (September 14, 2020), that too simply results from the fact that the segments represent different steps in the process of preparing natural gas for marketing. The more salient fact is that most of the polluting equipment, such as storage vessels, pneumatic pumps, and compressors, are found throughout the segments and emit the same pollutants that can be controlled by the same techniques and technologies, 81 FR 35832 (June 3, 2016), underscoring the interrelated functionality of the segments and the appropriateness of regulating them together as part of a single source category. The scope of the source category as defined in 2016, and proposed to be affirmed in this rule, is well within the reasonable bounds of the EPA's past practice in defining source categories, which sometimes even contain sources that are located in multiple distinct industries. See 40 CFR part 60, subpart Db (industrial-commercial-institutional steam generating units), 40 CFR part 60, subpart IIII (stationary compression ignition internal combustion engines). In this regard, the House Report correctly noted that “even the presence of large distinctions in equipment type and emissions profile across two segments would not necessarily preclude EPA from regulating those segments as a single source category, so long as the EPA could identify some meaningful relationship between them,” House Report at 7, as the EPA did in the 2016 Rule. Thus, the 2020 Policy Rule failed to articulate appropriate reasons to change the scope of the source category from what the EPA determined in the 2016 Rule. Having properly identified the scope of the source category as including the transmission and storage segment in the 2016 Rule, the EPA lawfully promulgated NSPS for sources in that segment.

The EPA also affirms that the 2016 Rule established an appropriate basis for promulgating methane NSPS from oil and gas sources, and that the 2020 Policy Rule erred on all grounds in rescinding the methane NSPS. The importance of taking action at this time, in accordance with the requirements of CAA section 111, to reduce the enormous amount of methane emissions from oil and gas sources, in light of the impacts on the climate of this pollution, cannot be overstated. As stated in section I, the Oil and Natural Gas Industry is the largest industrial emitter of methane in the U.S. Human emissions of methane, a potent GHG, are responsible for about one third of the warming due to well-mixed GHGs, the second most important human warming agent after carbon dioxide. According to the IPCC, strong, rapid, and sustained methane reductions are critical to reducing near-term disruption of the climate system and a vital complement to CO ₂ reductions critical in limiting the long-term extent of climate change and its destructive impacts. ¹⁶¹ The EPA previously determined, in the 2016 NSPS OOOOa rule, both that it had a rational basis to regulate methane emissions from the source category, and, in the alternative, that methane emissions from the Crude Oil and Natural Gas Source Category, contribute significantly to dangerous air pollution. 81 FR 35842-43, (June 3, 2016). The EPA is not reopening those determinations for comment in the present rulemaking.

¹⁶¹  See preamble section III for further discussion on the Crude Oil and Natural Gas Emissions and Climate Change, including discussion of the GHGs, VOCs and SO ₂ Emissions on Public Health and Welfare.

Contrary to the statements in the 2020 Policy Rule, the methane NSPS promulgated in the 2016 Rule cannot be said to be redundant with the VOC NSPS and therefore unnecessary. 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 highly irresponsible and also arbitrary and capricious under CAA section 307(d)(9)(A) 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. The fact that the EPA designed the methane NSPS so that sources could comply with them efficiently, through the same actions that the sources needed to take to comply with the VOC NSPS, did not thereby create redundancy. Further, the fact that methane NSPS but not the VOC NSPS trigger the regulatory requirements for existing sources makes clear that the two sets of requirements are not redundant. Indeed, if EPA had only regulated VOCs, it would only have been authorized to regulate new and modified sources, which comprise a small subset of polluting sources. By contrast, because the 2016 Rule also regulated methane, EPA was authorized and obligated to regulate hundreds of thousands of additional “existing” sources that comprise the vast majority of polluting sources. Accordingly, methane regulation was not “redundant” of VOC regulation. The 2020 Policy Rule's contrary position was based on a misinterpretation of CAA section 111 which overlooked that the provision integrates requirements for new and existing sources. See Nat'l Lime Ass'n v. EPA, 627 F.2d 416, 433 n.48 (D.C. Cir. 1980) (CAA section 111(b)(1)(A) listing of a source category is based on emissions from new and existing sources).

The EPA also reaffirms the 2016 Rule's statutory interpretation that the EPA is authorized to promulgate a NSPS for an air pollutant under CAA section 111(b)(1)(B) in a situation in which the EPA has previously determined that the source category causes or contributes significantly to dangerous air pollution and where the EPA has a rational basis for regulating the particular air pollutant in question that is emitted by the source category. 81 FR 35842 (June 3, 2016). The 2016 Rule noted the precedent in prior agency actions for the position that—following the listing of a source category—the EPA need provide only a rational basis for its exercise of discretion for which pollutants to regulate under section 111(b)(1)(B). See id. (citing National Lime Assoc. v. EPA, 627 F.2d 416, 426 & n.27 (D.C. Cir. 1980) (court discussed, but did not review, the EPA's reasons for not promulgating standards for NO _X , SO ₂ , and CO from lime plants). In addition, the Supreme Court in American Electric Power provided support for the rational basis statutory interpretation. 564 U.S. at 426-27 (“EPA [could] decline to regulate carbon-dioxide emissions altogether at the conclusion of its . . . [CAA section 111] rulemaking,” and such a decision “would not escape judicial review,” under the “arbitrary and capricious” standard of section 307(d)(9)(A)). As the House Report noted, the EPA's rational basis interpretation “is fully consistent with the provision[s] of section 111 and the section 307(d)(9) `arbitrary and capricious' standard.” House Report at 9.

The 2020 Policy Rule correctly noted that the CAA section 111(b)(1)(B) requirement that the EPA “shall promulgate . . . standards [of performance]” for air pollutants, coupled with the CAA section 111(a)(1) definition for “standard of performance” as, in relevant part, a “standard for emissions of air pollutants,” does not by its terms require that EPA promulgate NSPS for every air pollutant from the source category. But the rule erred in seeking to graft the CAA section 111(b)(1)(A) requirement for a SCF into CAA section 111(b)(1)(B). The language of CAA section 111(b)(1)(A) is clear: It requires the EPA Administrator to “include a category of sources in [the list for regulation] if in his judgment it causes, or contributes to, air pollution which may reasonably be anticipated to endanger public health or welfare.” (Emphasis added.) Congress thus specified that the required SCF is made on a category basis, not a pollutant-specific basis, and that once that finding is made (as it was for the Crude Oil and Natural Gas source category in 1979), the EPA may establish standards for pollutants emitted by the source category. In determining for which air pollutants to promulgate standards of performance, the EPA must act rationally, which, as noted above, essentially must ensure that the action does not fail the “arbitrary and capricious” standard under CAA section 307(d)(9)(A). The 2020 Policy Rule's objections to the rational basis standard on grounds that is “vague and not guided by any statutory criteria,” 85 FR 57034 (September 14, 2020), is incorrect. In making a rational basis determination, the EPA has considered the amount of the air pollutant emitted by the source category, both in absolute terms and by drawing comparisons, as well as the availability of control technologies. See National Lime Assoc. v. EPA, 627 F.2d 416, 426 & n.27 (D.C. Cir. 1980) (discussing EPA's reasons for not promulgating standards for NO _X , SO ₂ and CO from lime plants); 80 FR 64510, 64530 (October 23, 2015) (rational basis determination for GHGs from fossil fuel-fired electricity generating power plants); 73 FR 35838, 35859-60 (June 24, 2008) (providing reasons why the EPA was not promulgating GHG standards for petroleum refineries). Courts routinely review rules under the “arbitrary and capricious” standard, as noted in the House Report, at 11.

When the EPA is required to make an endangerment finding, the EPA also affirms that that finding should be made in consideration of the particular facts and circumstances, not a predetermined threshold. Accordingly, the EPA rejects the 2020 Policy Rule's position to the contrary. Section 111(b)(1)(A) of the CAA does not require that the SCF for the source category be based on “established criteria” or “standard or threshold.” See Coal. for Responsible Regulation, Inc. v. EPA, 684 F.3d 102, 122-23 (D.C. Cir. 2012) (“the inquiry [into whether an air pollutant endangers] necessarily entails a case-by-case, sliding-scale approach. . . . EPA need not establish a minimum threshold of risk or harm before determining whether an air pollutant endangers”). During the 50 years that it has made listing decisions, the EPA has always relied on the individual facts and circumstances. 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)). 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 reasonable to interpret section 111 to allow EPA the discretion to determine how best to assess significant contribution and endangerment based on the individual circumstances of each source category. On this point, as well, the EPA is in full agreement with the statements in the House Report. House Report at 9-10.

Finally, under CAA section 111(d)(1), once the EPA promulgates NSPS for certain air pollutants, including GHGs, the EPA is required to promulgate regulations, which the EPA terms EG, 40 CFR 60.22a, that in turn require States to promulgate standards of performance for existing sources of those air pollutants. The EPA agrees with the House Report and Senate statement that it is imperative to regulate methane emissions from the existing oil and gas sources that comprise the vast majority of polluting sources expeditiously under the authority of CAA section 111(d) and is proceeding with the process to do so in this rulemaking by publishing proposed EG. See section III.B.2. In 2019, the GHGI estimates for oil and natural gas production, and natural gas processing and transmission and storage segments that methane emissions equate to 182 MMT CO ₂ Eq. ¹⁶² In the U.S. the EPA has identified over 15,000 oil and gas owners and operators, around 1 million producing onshore oil and gas wells, about 5,000 gathering and boosting facilities, over 650 natural gas processing facilities, and about 1,400 transmission compression facilities.

¹⁶²  The 100-year GWP value of 25 for methane indicates that one ton of methane has approximately as much climate impact over a 100-year period as 25 tons of CO ₂ . The most recent IPCC AR6 assessment has estimated a slightly larger 100-year GWP of methane of almost 30 (specifically, either 27.2 or 29.8 depending on whether the value includes the CO ₂ produced by the oxidation of methane in the atmosphere). As mentioned earlier, because methane has a shorter lifetime than CO ₂ , 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 CO ₂ . See preamble section III for further discussion on the Crude Oil and Natural Gas Emissions and Climate Change, including discussion of the GHGs, VOCs and SO ₂ Emissions on Public Health and Welfare.

Some stakeholders have raised issues concerning the scope of pollutants subject to CAA section 111(d) by arguing that the exclusion in CAA section 111(d) for HAP covers not only those pollutants listed for regulation under CAA section 112, but also precludes the EPA from regulating a source category under CAA section 111(d) for any pollutant if that source category has been regulated under CAA section 112. The EPA agrees with its longstanding legal interpretation spanning multiple Administrations that the 111(d) exclusion does not preclude the agency from regulating a non-HAP pollutant from a source category under section 111(d) even if that source category is regulated under section 112. See American Lung Ass'n v. EPA, 980 F.3d 914, 980 (D.C. Cir. 2019) (referring to “EPA's three-decade-old . . . reading of the statutory amendments”), petition for cert. pending No. 20-1530 (filed April 29, 2021); 70 FR 15994, 16029 (March 29, 2005) (Clean Air Mercury Rule); 80 FR 64662, 64710 (Oct. 23, 2015) (Clean Power Plan); 84 FR 32520 (July 8, 2019) (Affordable Clean Energy Rule). The House Report agreed with this interpretation, noting that the contrary position is flawed because it ignores the overall statutory structure that Congress created in the CAA and would create regulatory gaps in which the EPA would not be able to regulate existing sources for some pollutants (such as methane) under CAA section 111(d) if those sources (but not pollutants) were already regulated for different pollutants under CAA section 112. House Report at 11-12. Moreover, the D.C. Circuit recently considered this precise issue and held that the EPA may both regulate a source category for HAP under CAA section 112 and regulate that same source category for different pollutants under CAA section 111(d). Am. Lung Assoc., 985 F.3d at 977-988. Accordingly, both Congress and the court have come to the same conclusion after reviewing the statutory language, a conclusion that is aligned with the EPA's longstanding position. We therefore proceed in the proposal to propose EGs for existing sources in the oil and gas source category.

IX. 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 this action, the EPA reviewed the standards in the 2016 NSPS OOOOa pursuant to CAA section 111(b)(1)(B). Based on this review, the EPA is proposing 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 proposing to retain the current standard for that affected facility. In addition to the actions on the standards in the 2016 NSPS OOOOa described in this section, the EPA is proposing standards for GHGs (in the form of limitation on methane) and VOCs for a number of new sources that are currently unregulated. The proposed 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 November 15, 2021.

Further, pursuant to CAA section 111(d), the EPA is proposing 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 the proposed EG OOOOc. While the proposed requirements in NSPS OOOOb would apply directly to new sources, the proposed 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 EPA evaluate control costs in this action?

Section 111 of the CAA requires that the EPA 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) (“ Lignite Energy Council” ). In Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427 (D.C. Cir. 1973) (“Essex Chemical” ), the court noted that “it is not unlikely that the industry and the EPA will disagree on the economic costs of various control techniques” and that it “has no desire or special ability to settle such a dispute.” Id. at 437. Rather, the court focused its review on “whether the standards as set are the result of reasoned decision-making.” Id. at 434. A standard that “is the result of the exercise of reasoned discretion by the Administrator [ ] cannot be upset by this Court.” Id. at 437.

As noted, CAA section 111 requires that the EPA consider cost in determining such system ( i.e., “BSER”), but it does not prescribe any criteria for such consideration. The courts have recognized that the EPA has “considerable discretion under [CAA] section 111,” Lignite Energy Council, 198 F.3d at 933, on how it considers cost under CAA section 111(a)(1). For example, in Essex Chemical, the D.C. Circuit stated that to be “adequately demonstrated,” the system must be “reasonably reliable, reasonably efficient, and . . . reasonably expected to serve the interests of pollution control without becoming exorbitantly costly in an economic or environmental way.” 486 F.2d at 433. The court has reiterated this limit in subsequent case law, including Lignite Energy Council, in which it stated: “EPA's choice will be sustained unless the environmental or economic costs of using the technology are exorbitant.” 198 F.3d at 933. In Portland Cement Association v. Train, the court elaborated by explaining that the inquiry is whether the costs of the standard are “greater than the industry could bear and survive.”  ¹⁶³ 513 F.2d 506, 508 (D.C. Cir. 1975). In Sierra Club v. Costle, the court provided a substantially similar formulation of the cost factor: “EPA concluded that the Electric Utilities' forecasted cost was not excessive and did not make the cost of compliance with the standard unreasonable. This is a judgment call with which we are not inclined to quarrel.” 657 F.2d 298, 343 (D.C. Cir. 1981). We believe that these various formulations of the cost factor—“exorbitant,” “greater than the industry could bear and survive,” “excessive,” and “unreasonable”—are synonymous; the D.C. Circuit has made no attempt to distinguish among them. For convenience, in this rulemaking, we will use the term “reasonable” to describe that our evaluation of costs is well within the boundaries established by this case law.

¹⁶³  The 1970 Senate Committee Report on the Clean Air Act stated: “The implicit consideration of economic factors in determining whether technology is `available' should not affect the usefulness of this section. The overriding purpose of this section would be to prevent new air pollution problems, and toward that end, maximum feasible control of new sources at the time of their construction is seen by the committee as the most effective and, in the long run, the least expensive approach.” S. Comm. Rep. No. 91-1196 at 16.

In evaluating whether the cost of a control is reasonable, the EPA considers various costs associated with such control, including capital costs and operating costs, and the emission reductions that the control can achieve. As discussed further below, the agency considers these costs in the context of the industry's overall capital expenditures and revenues. Cost-effectiveness analysis is also a useful metric, and a means of evaluating whether a given control achieves emission reduction at a reasonable cost. A cost-effectiveness analysis also allows comparisons of relative costs and outcomes (effects) of two or more options. In general, cost-effectiveness is a measure of the outcomes produced by resources spent. In the context of air pollution control options, cost-effectiveness typically refers to the annualized cost of implementing an air pollution control option divided by the amount of pollutant reductions realized annually. 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 provides a metric to compare the relative cost and emissions impacts of various control options.

The estimation and interpretation of cost-effectiveness values is relatively straightforward when an abatement measure is implemented for the purpose of controlling a single pollutant, such as for the controls included as presumptive standards in the proposed EG OOOOc to address methane emissions from existing sources in the Crude Oil and Natural Gas source category. In other circumstances, air pollution reduction programs require reductions in emissions of multiple pollutants, as with the NSPS for the Crude Oil and Natural Gas source category, which regulates both GHG and VOC. In such cases, multipollutant controls (controls that achieve reductions of both pollutants through the same techniques and technologies) may be employed, and consequently, there is a need for determining cost-effectiveness for a control option across multiple pollutants (or classes of multiple pollutants).

During the rulemaking for NSPS OOOOa, we evaluated a number of approaches for considering the cost-effectiveness of the available multipollutant controls for reducing both methane and VOC emissions. See 80 FR 56593, 56616 (September 18, 2015). In that rulemaking, we used two approaches for considering the cost-effectiveness of control options that reduce both VOC and methane emissions; we are proposing to use these same two cost-effectiveness approaches, along with other factors discussed further below, in considering the cost of requiring control for the proposed NSPS OOOOb. One approach, which we refer to as the “single pollutant cost-effectiveness approach,” assigns all costs to the emission reduction of one pollutant and zero to all other concurrent reductions. If the cost is reasonable for reducing any of the targeted pollutants alone, the cost of such control is clearly reasonable for the concurrent emission reduction of all the other regulated pollutants because they are being reduced at no additional cost. While this approach assigns all costs to only a portion of the emission reduction and thus may overstate the cost for that assigned portion, it does not overstate the overall cost. Instead, it acknowledges that the reductions of the other regulated pollutant are intended as opposed to incidental. This approach is simple and straightforward in application: If the multipollutant control is cost effective for reducing emissions of either of the targeted pollutants, it is clearly cost effective for reducing all other targeted emissions that are being achieved simultaneously.

A second approach, which we term for the purpose of this rulemaking a “multipollutant cost-effectiveness approach,” apportions the annualized cost across the pollutant reductions addressed by the control option in proportion to the relative percentage reduction of each pollutant controlled. In the case of the Crude Oil and Natural Gas source category, both methane and VOC are reduced in equal proportions, relative to their respective baselines by the multipollutant control option ( i.e., where control is 95 percent reduction, methane and VOC are both simultaneously reduced by 95 percent by the multipollutant control). As a result, under the multipollutant cost-effectiveness approach, half of the control costs are allocated to methane and the other half to VOC. Under this approach, control is cost effective if it is cost effective for both VOC and methane.

We believe that both the single pollutant and multipollutant cost-effectiveness approaches discussed above are appropriate for assessing the reasonableness of the multipollutant controls considered in this action for new sources. As such, in the individual BSER analyses in section XII below, if a device is cost-effective under either of these two approaches, we find it to be cost-effective. The EPA has considered similar approaches in the past when considering multiple pollutants that are controlled by a given control option. ¹⁶⁴ The EPA recognizes, however, not all situations where multipollutant controls are applied are the same, and that other types of approaches might be appropriate in other instances.

¹⁶⁴  See, e.g., 73 FR 64079-64083 and EPA Document I.D. EPA-HQ-OAR-2004-0022-0622, EPA-HQ-OAR-2004-0022-0447, EPA-HQ-OAR- 2004-0022-0448.

As mentioned above, as part of its consideration of control costs in the individual BSER analyses in Section XII, the EPA evaluated cost-effectiveness using the single pollutant and multipollutant cost-effectiveness approaches. We estimated the cost-effectiveness values of the proposed control options using available information, including various studies, information submitted in previous rulemakings from the affected industry, and information provided by small businesses. The EPA provides the cost effectiveness estimates for reducing VOC and methane emissions for various control options considered in section XII. As discussed in that section, the EPA finds cost-effectiveness values up to $5,540/ton of VOC reduction to be reasonable for controls that we have identified as BSER in this proposal. 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. With respect to methane, the EPA finds the cost-effectiveness values up to $1,800/ton of methane reduction to be reasonable for controls that we have identified as BSER in this proposal. Unlike VOC, the EPA does not have a long regulatory history to draw upon in assessing the cost effectiveness of controlling methane, as the 2016 NSPS OOOOa was the first national standard for reducing methane emissions. However, as explained below, the EPA has previously determined that methane cost-effectiveness values for the controls identified as BSER for the 2016 NSPS OOOOa, which range up to $2,185/ton of methane reduction, represent reasonable costs for the industry as a whole to bear; and because the cost-effectiveness estimates for the proposed standards in this action are comparable to the cost-effectiveness values estimated for the controls that served as the basis ( i.e., BSER) for the standards in the 2016 NSPS OOOOa, we consider the proposed standards to also be cost effective and reasonable.

The BSER determinations from the 2016 NSPS OOOOa also support the EPA's conclusion that the cost-effectiveness values associated with the proposed standards in this action are reasonable. As mentioned above, for 2016 NSPS OOOOa, the highest estimate that the EPA considered cost effective for methane reduction was $2,185/ton, which was the estimate for converting a natural gas driven diaphragm pump to an instrument air pump at a gas processing plant. ^165 166 80 FR 56627; see also, NSPS OOOOa Final TSD at 93, Table 6-7. The EPA estimated that the cost-effectiveness of this option, a common practice at gas processing plants, could be up to $2,185/ton of methane reduction under the single pollutant cost-effectiveness approach and $1,093/ton under the multipollutant cost effectiveness approach; the EPA found “the control to be cost effective under either approach.” Id. Accordingly, the EPA finalized requirements in the 2016 NSPS OOOOa that require zero emissions from diaphragm pumps at gas processing plants, consistent with the Agency's BSER determination.

¹⁶⁵  As discussed in section X.A, the EPA incorrectly stated in the 2020 Technical Rule that $738/ton of methane reduction was the highest cost-effectiveness value that the EPA determined to be reasonable for methane reduction in the 2016 NSPS OOOOa.

¹⁶⁶  While in that rulemaking the EPA found quarterly monitoring of fugitive emissions at well sites not cost effective at $1,960/ton of methane reduced using the single pollutant approach (and $980 using the multi-pollutant approach), the EPA emphasized that this conclusion was not intended to “preclude the EPA from taking a different approach in the future including requiring more frequent monitoring (e.g., quarterly).” 81 FR 35855-6 referencing Background Technical Support Document for the New Source Performance Standards 40 CFR part 60 subpart OOOOa (May 2016), at 49, Table 4-11 and 52, Table 4-14. Further, several states have issued regulations and industry has voluntarily taken steps to reduce emissions. This combined with greater knowledge and understanding of the industry leads us to find these values cost-effective. As discussed in this section IX.B, cost-effectiveness is one—not the only—factor in EPA's consideration of control costs. In fact, in this action, the EPA is proposing different monitoring frequencies based on well site baseline emissions, even though the EPA found quarterly monitoring to be cost effective for all well sites. Please see section XII.A for a detailed discussion on this proposal.

The 2016 NSPS OOOOa also requires 95 percent methane and VOC emission reduction from wet-seal centrifugal compressors. The BSER for this standard was capturing and routing the emissions to a control combustion device, a widely used control in the oil and gas sector for reducing emissions from storage vessels and pumps, in addition to centrifugal compressors. 80 FR 56620. The EPA estimated cost-effectiveness values of up to $1,093/ton of methane reduction for this option. See NSPS OOOOa Final TSD at 114, Table 7-9. With respect to other controls identified as BSER in the 2016 NSPS OOOOa, their cost-effectiveness estimates were comparable to or well below the estimates from the 2016 NSPS OOOOa rulemaking discussed above. In light of this, and because sources have been complying with the 2016 NSPS OOOOa for years, we believe that the cost-effectiveness values for the controls identified as BSER for the 2016 NSPS OOOOa, which range up to $2,185/ton of methane reduction, represent reasonable, rather than excessive, costs for the industry as a whole to bear. As shown in the individual BSER analyses in Section XII and the NSPS OOOOb and EG OOOOc TSD for this proposal, the cost-effectiveness values for the proposed standards in this action are comparable to the cost-effectiveness values for the standards in NSPS OOOOa. We, therefore, similarly consider the cost-effectiveness values for the proposed standards to be reasonable. That the proposed standards reflect the kinds of controls that many companies and sources around the country are already implementing underscore the reasonableness of these control measures.

In addition to evaluating the annual average cost-effectiveness of a control option, the EPA also considers the incremental costs associated with increasing the stringency of the standards from one level of control to another level of control that achieves more emission reductions. The incremental cost of control provides insight into how much it costs to achieve the next increment of emission reductions through application of each increasingly stringent control options, and thus is a useful tool for distinguishing among the effects of more and less stringent control options. For example, during the rulemaking for the 2012 NSPS OOOO, the EPA considered the incremental cost effectiveness of changing the originally promulgated standards for leaks at gas processing plants, which were based on NSPS subpart VV, to the more stringent NSPS subpart VVa-level program. See 76 FR 52738, 52755 (August 23, 2011). The EPA generally finds the incremental cost-effectiveness to be reasonable if it is consistent with the costs that the Agency considers reasonable in its evaluation of annual average cost-effectiveness.

As shown in the NSPS OOOOb and EG OOOOc TSD for this action, the EPA estimated control costs both with and without savings from recovered gas that would otherwise be emitted. When determining the overall costs of implementation of the control technology and the associated cost-effectiveness, the EPA reasonably takes into account any expected revenues from the sale of natural gas product that would be realized as a result of avoided emissions that result from implementation of a control. Such a sale would offset regulatory costs and so should be included to accurately assess the overall costs and the cost-effectiveness of the standard. In our analysis we consider any natural gas that is either recovered or that is not emitted as a result of a control option as being “saved.” We estimate that one thousand standard cubic feet (Mcf) of natural gas is valued at $3.13 per Mcf. ¹⁶⁷ Our cost analysis then applies the monetary value of the saved natural gas as an offset to the control cost. ¹⁶⁸ This offset applies where, in our estimation, the monetary savings of the natural gas saved can be realized by the affected facility owner or operator and not 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 these assumptions are presented in section 2 of the RIA associated with this action, which is in the docket.

¹⁶⁷  This value reflects the forecasted Henry Hub price for 2022 from: U.S. Energy Information Administration. Short-Term Energy Outlook. https://www.eia.gov/outlooks/steo/archives/may21.pdf. Release Date: May 11, 2021.

¹⁶⁸  While the EPA presents cost-effectiveness with and without cost savings, the BSER is determined based on the cost-effectiveness without cost savings in all cases.

We also completed two additional analyses to further inform our determination of whether the cost of control is reasonable, similar to compliance cost analyses we have completed for other NSPS. ¹⁶⁹ First, we compared the capital costs that would be incurred to comply with the proposed standards to the industry's estimated new annual capital expenditures. This analysis allowed us to compare the capital costs that would be incurred to comply with the proposed standards to the level of new capital expenditures that the industry is incurring in the absence of the proposed standards. We then determined whether the capital costs appear reasonable in comparison to the industry's current level of capital spending. Second, we compared the annualized costs that would be incurred to comply with the standards to the industry's estimated annual revenues. This analysis allowed us to evaluate the annualized costs as a percentage of the revenues being generated by the industry.

¹⁶⁹  For example, see our compliance cost analysis in “Regulatory Impact Analysis (RIA) for Residential Wood Heaters NSPS Revision. Final Report.” U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards. EPA-452/R-15-001, February 2015.

The EPA has evaluated incremental capital costs in a manner similar to the analyses described above in prior new source performance standards, and in those prior standards, the Agency's determinations that the costs were reasonable were upheld by the courts. For example, the EPA estimated that the costs for the 1971 NSPS for coal-fired electric utility generating units were $19 million for a 600 MW plant, consisting of $3.6 million for particulate matter controls, $14.4 million for sulfur dioxide controls, and $1 million for nitrogen oxides controls, representing a total 15.8 percent increase in capital costs above the $120 million cost of the plant. ¹⁷⁰See 1972 Supplemental Statement, 37 FR 5767, 5769 (March 21, 1972). The D.C. Circuit upheld the EPA's determination that the costs associated with the final 1971 standard were reasonable, concluding that the EPA had properly taken costs into consideration. Essex Chemical, 486 F. 2d at 440. Similarly, in Portland Cement Association v. Ruckelshaus, the D.C. Circuit upheld the EPA's consideration of costs for a standard of performance that would increase capital costs by about 12 percent, although the rule was remanded due to an unrelated procedural issue. 486 F.2d 375, 387-88 (D.C. Cir. 1973). Reviewing the EPA's final rule after remand, the court again upheld the standards and the EPA's consideration of costs, noting that “[t]he industry has not shown inability to adjust itself in a healthy economic fashion to the end sought by the Act as represented by the standards prescribed.” Portland Cement Assn. v. Train, 513 F. 2d at 508.

¹⁷⁰  Assuming these costs were denominated in 1971 dollars, converting the costs from 1971 to 2019 dollars using the Gross Domestic Product-Implicit Price Deflator, the costs for the 1971 NSPS for coal-fired electric utility generating units were $94 million for a 600 MW plant, consisting of $18 million for particulate matter controls, $71 million for sulfur dioxide controls, and $5 million for nitrogen oxides controls, representing a 15.8 percent increase in capital costs above the $590 million cost of the plant.

In this action, for the capital expenditures analysis, we divide the nationwide capital expenditures projected to be spent to comply with the proposed standards by an estimate of the total sector-level new capital expenditures for a representative year to determine the percentage that the nationwide capital cost requirements under the proposal represent of the total capital expenditures by the sector. We combine the compliance-related capital costs under the proposed standards for the NSPS and for the presumptive standards in the proposed EG to analyze the potential aggregate impact of the proposal. The EAV of the projected compliance-related capital expenditures over the 2023 to 2035 period is projected to be about $510 million in 2019 dollars. We obtained new capital expenditure data for relevant NAICS codes for 2018 from the U.S. Census 2019 Annual Capital Expenditures Survey. ¹⁷¹ Estimates of new capital expenditures are available for 2019, but we chose to use 2018 because the 2019 new capital expenditure data for pipeline transportation of natural gas (NAICS 4862) are withheld to avoid disclosing data for individual enterprises, and the withholding of that NAICS causes the totals for 2019 to be lower than for 2018. According to these data, new capital expenditures for the sector in 2018 were about $155 billion in 2019 dollars. Comparing the EAV of the projected compliance-related capital expenditures under the proposal with the 2018 total sector-level new capital expenditures yields a percentage of about 0.3 percent, which is well below the percentage increase previously upheld by the courts, as discussed above.

¹⁷¹  U.S. Census Bureau, 2019 Annual Capital Expenditures Survey, Table 4b. Capital Expenditures for Structures and Equipment for Companies With Employees by Industry: 2018 Revised, http://www.census.gov/econ/aces/index.html, accessed September 4, 2021.

For the comparison of compliance costs to revenues, we use the EAV of the projected compliance costs without and with projected revenues from product recovery under the proposal for the 2023 to 2035 period then divided the nationwide annualized costs by the annual revenues for the appropriate NAICS code(s) for a representative year 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 proposed EG to analyze the potential aggregate impact of the proposal. The EAV of the associated increase in compliance cost over the 2023 to 2035 period is projected to be about $1.2 billion without revenues from product recovery and about $760 million 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. ¹⁷² According to these data, 2018 receipts for the sector were about $358 billion in 2019 dollars. Comparing the EAV of the projected compliance costs under the proposal with the sector-level receipts figure yields a percentage of about 0.3 percent without revenues from product recovery and about 0.2 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 Chapter 15 of the TSD for this action, which is in the public docket.

¹⁷²  2017 County Business Patterns and Economic Census. The Number of Firms and Establishments, Employment, Annual Payroll, and Receipts by Industry and Enterprise Receipts Size: 2017, https://www.census.gov/programs-surveys/susb/data/tables.2017.html, accessed September 4. 2021.

In considering the costs of the control options evaluated in this action, the EPA estimated the control costs under various approaches, including annual average cost-effectiveness and incremental cost-effectiveness of a given control. The EPA also performed two broad comparisons to consider the costs of control: First, we compared the projected compliance-related capital expenditures to recent sector-level capital expenditures; second, we compared the projected total compliance costs to recent sector-level annual revenues. In its cost-effectiveness analyses, the EPA recognized and took into account that these multi-pollutant controls reduce both VOC and methane emissions in equal proportions, as reflected in the single-pollutant and multipollutant cost effectiveness approaches. The EPA also considered cost saving from the natural gas recovered instead of vented due to the proposed controls. Based on all of the considerations described above, the EPA concludes that the costs of the controls that serve as the basis of the standards proposed in this action are reasonable. The EPA solicits comment on its approaches for considering control costs, as well as the resulting analyses and conclusions.

X. Summary of Proposed Action for NSPS OOOOa

As described above in sections IV and VIII, the 2020 Policy Rule rescinded all NSPS regulating emissions of VOC and methane from sources in the natural gas transmission and storage segment of the Oil and Natural Gas Industry and NSPS regulating methane from sources in the industry's production and processing segments. As a result, the 2020 Technical Rule only amended the VOC standards for the production and processing segments in the 2016 NSPS OOOOa, because those were the only standards that remained at the time that the 2020 Technical Rule was finalized. The 2020 Technical Rule included amendments to address a range of technical and implementation issues in response to administrative petitions for reconsideration and other issues brought to the EPA's attention since promulgating the 2016 NSPS. These included, among other issues, those associated with the implementation of the fugitive emissions requirements and pneumatic pump standards, provisions to apply for the use of an AMEL, provisions for determining applicability of the storage vessel standards, and modification to the engineer certifications. In 2018, the EPA proposed amendments to address these technical issues for both the methane and VOC standards in the 2016 NSPS OOOOa, and in some instances for sources in the transmission and storage segment. 83 FR 52056, October 15, 2018. However, because the methane standards and all standards for the transmission and storage segment were removed via the 2020 Policy Rule prior to the finalization of the 2020 Technical Rule, the final amendments in the 2020 Technical Rule apply only to the 2016 NSPS OOOOa VOC standards for the production and processing segments. Additionally, the 2020 Policy Rule amended the 2012 NSPS OOOO to remove the VOC requirements for sources in the transmission and storage segment, but the Technical Rule did not amend the 2012 NSPS OOOO.

Under the CRA, a rule that is subject to a joint resolution of disapproval “shall be treated as though such rule had never taken effect.” 5 U.S.C. 801(f)(2). Thus, because it was disapproved under the CRA, the 2020 Policy Rule is treated as never having taken effect. As a result, the requirements in the 2012 NSPS OOOO and 2016 NSPS OOOOa that the 2020 Policy Rule repealed ( i.e., the VOC and methane standards for the transmission and storage segment, as well as the methane standards for the production and processing segments) must be treated as being in effect immediately upon enactment of the joint resolution on June 30, 2021. Any new, reconstructed, or modified facility that would have been subject to the 2012 or 2016 NSPS (“affected facility”) but for the 2020 Policy Rule was subject to those NSPS as of that date. The CRA resolution did not address the 2020 Technical Rule; therefore, the amendments made in the 2020 Technical Rule, which apply only to the VOC standards for the production and processing segments in the 2016 NSPS OOOOa, remain in effect. As a result, sources in the production and processing segments are now subject to two different sets of standards: ¹⁷³ One for methane based on the 2016 NSPS OOOOa, and one for VOC that include the amendments to the 2016 NSPS OOOOa made in the 2020 Technical Rule. Sources in the transmission and storage segment are subject to the methane and VOC standards as promulgated in either the 2012 NSPS OOOO or the 2016 NSPS OOOOa, as applicable. ¹⁷⁴ The EPA recognizes that certain amendments made to the VOC standards in the 2016 NSPS OOOOa in the 2020 Technical Rule, which addressed technical and implementation issues in response to administrative petitions for reconsideration and other issues brought to the EPA's attention since promulgating the 2016 NSPS OOOOa rule could also be appropriate to address similar implementation issues associated with the methane standards for the production and processing segments and the methane and VOC standards for the transmission and storage segment. In fact, as mentioned above, such revisions were proposed in 2018 but not finalized because these standards were removed by the 2020 Policy Rule prior to the EPA's promulgation of the 2020 Technical Rule. In light of the above, the EPA is proposing to revise 40 CFR part 60, subpart OOOOa, to apply certain amendments made in the 2020 Technical Rule to the 2016 NSPS OOOOa for methane from the production and processing segments and/or the 2016 NSPS OOOOa for methane and VOC from the transmission and storage segment, as specified in this section.

¹⁷³  The only exception is storage vessels, for which the EPA did not promulgate methane standards in the 2016 NSPS OOOOa.

¹⁷⁴  For the EPA's full explanation of its initial guidance to stakeholders on the impact of the CRA, please see https://www.epa.gov/system/files/documents/2021-07/qa_cra_for_2020_oil_and_gas_policy_rule.6.30.2021.pdf.

In this action, the EPA is proposing amendments to the 2016 NSPS OOOOa to (1) rescind the revisions to the VOC fugitive emissions monitoring frequencies at well sites and gathering and boosting compressor stations in the 2020 Technical Rule as those revisions were not supported by the record for that rule, or by our subsequent information and analysis, and (2) adjust other modifications made in the 2020 Technical Rule to address technical and implementation issues that result from the CRA disapproval of the 2020 Policy Rule. The EPA is not reopening any of these prior rulemakings for any other purpose in this proposed action. Specifically, the EPA is not reopening any of the determinations made in the 2012 NSPS OOOO. In the final rule for this action, the EPA will update the NSPS OOOO and NSPS OOOOa regulatory text 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. In accordance with 5 U.S.C. 553(b)(3)(B), the EPA is not soliciting comment on these updates. Moreover, the EPA is not reopening the methane standards as finalized in the 2016 NSPS OOOOa, except as to the specific issues discussed below, nor is the EPA reopening any other portions of the 2016 Rule. The EPA is also not reopening any determinations made in the 2020 Technical Rule, except as to the specific issues discussed below. Finally, the reopening of determinations made with respect to the VOC standards in the 2020 Technical Rule does not indicate any intent to also reopen the methane standards for the same affected facilities.

A. Amendments to Fugitive Emissions Monitoring Frequency

The EPA is proposing to repeal its amendments in the 2020 Technical Rule that (1) exempted low production well sites from monitoring fugitive emissions and (2) changed from quarterly to semiannual monitoring of VOC emissions at gathering and boosting compressor stations. The EPA has authority to reconsider a prior action “as long as `the new policy is permissible under the statute. . . , there are good reasons for it, and . . . the agency believes it to be better.' ” FCC v. Fox Television Stations, Inc., 556 U.S. 502, 515, 129 S. Ct. 1800, 173 L. Ed. 2d738 (2009).

The 2016 NSPS OOOOa, as initially promulgated, required semiannual monitoring of VOC and methane emissions at all well sites, including low production well sites. It also required quarterly monitoring of compressor stations, including gathering and boosting compressor stations. After issuing the 2020 Policy Rule, which removed all methane standards applicable to the production and processing segments and all methane and VOC standards applicable to the transmission and storage segment, the EPA promulgated the 2020 Technical Rule that further amended the VOC standards in the production and processing segment. In particular, based on its revised cost analyses, the EPA exempted low production well sites from monitoring VOC fugitive emissions and changed the frequency of monitoring VOC fugitive emissions from quarterly to semiannually at gathering and boosting compressor stations. However, as a result of the CRA disapproval of the 2020 Policy Rule, the low production well sites and the gathering and boosting compressor stations continue to be subject to semiannual and quarterly monitoring of methane emissions respectively. While it is possible for these affected facilities to comply with both the VOC and methane monitoring standards that are now in effect, as compliance with the more stringent standard would be deemed compliance with the other, the EPA reviewed its decisions to amend the VOC monitoring frequencies for these affected facilities as well as the underlying record and, for the reasons explained below, no longer believe that the amendments are appropriate. Therefore, the EPA is proposing to repeal these amendments and restore the semiannual and quarterly monitoring requirements for low production well sites and gathering and boosting compressor stations, as originally promulgated in the 2016 NSPS OOOOa, for both methane and VOC.

1. Low Production Well Sites

As mentioned above, low production well sites are subject to semiannual monitoring of fugitive methane emissions. The EPA is proposing to repeal the amendment in the 2020 Technical Rule exempting low production well sites from monitoring fugitive VOC emissions because the analysis for the 2020 Technical Rule supports retaining the semiannual monitoring requirement when regulating both VOC and methane emissions. While the 2020 Technical Rule amended only the VOC standards in the production and processing segments, the EPA evaluated both methane and VOC reductions in its final technical support document (TSD) (2020 TSD), including the costs associated with different monitoring frequencies under the multipollutant approach, ¹⁷⁵ which the EPA considers a reasonable approach when regulating multiple pollutants. As shown in the 2020 TSD, under the multipollutant approach, the cost of semiannual monitoring at low production well sites is $850 per ton of methane and $3,058 per ton of VOC reduced, both of which are well within the range of what the EPA considers to be cost effective. ¹⁷⁶ Nevertheless, the EPA stated in the 2020 Technical Rule that “even if we had not rescinded the methane standards in the 2020 Policy Rule, we would still conclude that fugitive emissions monitoring, at any of the frequencies evaluated, is not cost effective for low production well sites.” This statement, however, is inconsistent with the conclusions on what costs are reasonable for the control of methane emissions as discussed in this proposal in section IX. More importantly, as an initial matter, this statement was based on the EPA's observation in the 2020 Technical Rule that the $850 per ton of methane reduced is “greater than the highest value for methane that the EPA determined to be reasonable in the 2016 NSPS subpart OOOOa,” which the EPA incorrectly identified as $738/ton; the record for the 2016 NSPS OOOOa shows that the EPA considered value as high as $2,185/ton to be cost effective for methane reduction. 80 FR 56627; see also, NSPS OOOOa Final TSD at 93, Table 6-7. Further, even with the incorrect observation, the EPA did not conclude in the 2020 Technical Rule that $850 per ton of methane reduced is therefore unreasonable. 85 FR 57420. In fact, the EPA reiterated its prior determination that “a cost of control of $738 per ton of methane reduced did not appear excessive,” and that value was only $112 less than the value that the EPA had incorrectly identified as the highest methane cost-effectiveness value from the 2016 NSPS OOOOa. As discussed above, in fact $738/ton is well within the costs that the EPA concludes to be reasonable in the 2016 NSPS OOOOa as well as in this document. Also, as explained in section XI.A.2, due to the wide variation in well characteristics, types of oil and gas products and production levels, gas composition, and types of equipment at well sites, there is considerable uncertainty regarding the relationship between the fugitive emissions and production levels. Accordingly, the EPA no longer believes that production levels provide an appropriate threshold for any exemption from fugitive monitoring. See section XI.A.2 for additional discussion on the proposed emission thresholds for well site fugitive emissions in place of production-based model plants. In light of the above, the EPA is proposing to remove the exemption of low production well sites from fugitive VOC emissions monitoring, thereby restoring the semiannual monitoring requirement established in the 2016 NSPS OOOOa.

¹⁷⁵  For purposes of the multipollutant approach, we assume that emissions of methane and VOC are controlled at the same time, therefore, half of the cost is apportioned to the methane emission reductions and half of the cost is apportioned to VOC emission reductions.

¹⁷⁶  See 2020 NSPS OOOOa Technical Rule TSD at Docket ID No. EPA-HQ-OAR-2017-0483-2291. See also section IX, which provides that the cost effectiveness values for the controls that we have identified as BSER in this action range from $2,200/ton to $5,800/ton VOC reduction and $700/ton to $2,100/ton of methane reduction. As explained in that section, these controls reflect emission reduction technologies and methods that many owners and operators in the oil and gas industry have employed for years, either voluntarily or due to the 2012 and 2016 NSPS, as well as State or other requirements.

2. Gathering and Boosting Compressor Stations

The EPA is proposing to repeal its amendment to the VOC monitoring frequency for gathering and boosting compressor stations in the 2020 Technical Rule because the EPA believes that amendment was made in error. In that rule, the EPA noted that, based on its revised cost analysis, quarterly monitoring has a cost effectiveness of $3,221/ton of VOC emissions and an incremental cost of $4,988/ton of additional VOC emissions reduced between the semiannual and quarterly monitoring frequencies. While the EPA observed that semiannual monitoring is more cost effective than quarterly, the EPA nevertheless acknowledged that “these values (total and incremental) are considered cost-effective for VOC reduction based on past EPA decisions, including the 2016 rulemaking.” 85 FR 57421, September 15, 2020. The EPA instead identified two additional factors to support its decision to forgo quarterly monitoring. First, the EPA stated that the “Oil and Gas Industry is currently experiencing significant financial hardship that may weigh against the appropriateness of imposing the additional costs associated with more frequent monitoring.” However, the EPA did not offer any data regarding the financial hardship, significant or otherwise, the industry was experiencing. While the rule cited to several articles on the impact of COVID-19 on the industry, the EPA did not discuss any aspect of any of the cited articles that led to its conclusion of “significant financial hardship” on the industry. Nor did the EPA explain how reducing the frequency of a monitoring requirement that had been in effect since 2016 would meaningfully affect the industry's economic circumstances in any way or weigh those considerations against the forgone emission reductions that would result from reducing monitoring frequency.

Second, the EPA generally asserted that “there are potential efficiencies, and potential cost savings, with applying the same monitoring frequencies for well sites and compressor stations.” Again, the EPA did not describe what the potential efficiencies are or the extent of cost savings that would justify forgoing quarterly monitoring, or weigh those efficiencies and cost savings against the forgone emission reductions that would result from reducing the monitoring frequency for compressor stations. Nor did we explain why the Agency's 2016 BSER determination that quarterly monitoring was achievable and cost-effective was incorrect in light of these asserted efficiencies. On the contrary, based on the compliance records for the 2016 NSPS OOOOa, there is no indication that compressor stations experienced hardship or difficulty in complying with the quarterly monitoring requirement. Further, as discussed in section XII.A.1.b, our analysis for NSPS OOOOb and EG OOOOc confirms that quarterly monitoring remains both achievable and cost-effective for compressor stations, and several State agencies also have rules that require quarterly monitoring at compressor stations. For the reasons stated above, the EPA concludes that it lacked justification and thus erred in revising the VOC monitoring frequency for gathering and boosting compressor stations from quarterly to semiannual. The EPA is therefore proposing to repeal that amendment, thereby restoring the quarterly monitoring requirement for gathering and boosting compressor stations, as established in the 2016 NSPS OOOOa.

B. Technical and Implementation Amendments

In the following sections, the EPA describes a series of proposed amendments to 2016 NSPS OOOOa for methane to align the 2016 methane standards with the current VOC standards (which were modified by the 2020 Technical Rule). We describe the supporting rationales that were provided in the 2020 Technical Rule for modifying the requirements applicable to the VOC standards, and explain why the amendments would also appropriately apply to the reinstated methane standards.

1. Well Completions

In the 2020 Technical Rule, the EPA made certain amendments to the VOC standards for well completions in the 2016 NSPS OOOOa. For the same reasons provided in the 2020 Technical Rule and reiterated below, the EPA is proposing to apply the same amendments to the methane standards for well completions in the 2016 NSPS OOOOa.

First, the EPA is proposing to amend the 2016 NSPS OOOOa methane standards for well completions to allow the use of a separator at a nearby centralized facility or well pad that services the well affected facility during flowback, as long as the separator can be utilized as soon as it is technically feasible for the separator to function. The well completion requirements, as promulgated in 2016, had required that the owner or operator of a well affected facility have a separator on site during the entire flowback period. 81 FR 35901, June 3, 2016. In the 2020 Technical Rule, the EPA amended this provision to allow the separator to be at a nearby centralized facility or well pad that services the well affected facility during flowback as long as the separator can be utilized as soon as it is technically feasible for the separator to function. See 40 CFR 60.5375a(a)(1)(iii). As explained in that rulemaking (85 FR 57403) and previously in the 2016 NSPS OOOOa final rule preamble, “[w]e anticipate a subcategory 1 well to be producing or near other producing wells. We therefore anticipate reduced emission completion (REC) equipment (including separators) to be onsite or nearby, or that any separator brought onsite or nearby can be put to use.” 81 FR 35852, June 3, 2016. For the same reason, the EPA is proposing to make the same amendment to the methane standards for well completions.

Additionally, the 2020 Technical Rule amended 40 CFR 60.5375a(a)(1)(i) to clarify that the separator that is required during the initial flowback stage may be a production separator as long as it is also designed to accommodate flowback. As explained in the preamble to the final 2020 Technical Rule, when a production separator is used for both well completions and production, the production separator is connected at the onset of the flowback and stays on after flowback and at the startup of production. 85 FR 57403, September 15, 2020. For the same reason, the EPA is proposing the same clarification apply to the methane standards for well completions.

The 2020 Technical Rule also amended the definition of flowback. In 2016, the EPA defined “flowback” as the process of allowing fluids and entrained solids to flow from a well following a treatment, either in preparation for a subsequent phase of treatment or in preparation for cleanup and returning the well to production. Flowback also means the fluids and entrained solids that emerge from a well during the flowback process. The flowback period begins when material introduced into the well during the treatment returns to the surface following hydraulic fracturing or refracturing. The flowback period ends when either the well is shut in and permanently disconnected from the flowback equipment or at the startup of production. The flowback period includes the initial flowback stage and the separation flowback stage. 81 FR 35934, June 3, 2016.

The 2020 Technical Rule amended this definition by adding a clarifying statement that “[s]creenouts, coil tubing cleanouts, and plug drill-outs are not considered part of the flowback process.” 40 CFR 60.5430a. In the proposal for the 2020 Technical Rule, the EPA explained that screenouts, coil tubing cleanouts, and plug drill outs are functional processes that allow for flowback to begin; as such, they are not part of the flowback. 83 FR 52082, October 15, 2018. In conjunction with this amendment, the 2020 Technical Rule added definitions for screenouts, coil tubing cleanouts, and plug drill outs. See 40 CFR 60.5430a. Specifically, a screenout is an attempt to clear proppant from the wellbore in order to dislodge the proppant out of the well. A coil tubing cleanout is a process where an operator runs a string of coil tubing to the packed proppant within a well and jets the well to dislodge the proppant and provide sufficient lift energy to flow it to the surface. A plug drill-out is the removal of a plug (or plugs) that was used to isolate different sections of the well. For the reason stated above, the EPA is proposing to apply the definitions of flowback, screenouts, coil tubing cleanouts, and plug drill outs that were finalized in the 2020 Technical Rule to the methane standards for well completions in the 2016 NSPS OOOOa.

Finally, the 2020 Technical Rule amended specific recordkeeping and reporting requirements for the VOC standards for well completions, and the EPA is proposing to apply these amendments to the methane standards for well completions in the 2016 NSPS OOOOa. For the reasons explained in 83 FR 52082, the 2020 Technical Rule requires that for each well site affected facility that routes flowback entirely through one or more production separators, owners and operators must record and report only the following data elements:

• Well Completion ID;

• Latitude and longitude of the well in decimal degrees to an accuracy and precision of five (5) decimals of a degree using North American Datum of 1983;

• U.S. Well ID;

• The date and time of the onset of flowback following hydraulic fracturing or refracturing or identification that the well immediately starts production; and

• The date and time of the startup of production.

While the 2020 Technical Rule removed certain reporting requirements ( e.g., information about when a separator is hooked up or disconnected during flowback) as unnecessary or redundant, 85 FR 57403, the rule added a requirement that for periods where salable gas is unable to be separated, owners and operators must record and report the date and time of onset of flowback, the duration and disposition of recovery, the duration of combustion and venting (if applicable), reasons for venting (if applicable), and deviations.

As explained in the preamble to the proposal for the 2020 Technical Rule, when a production separator is used for both well completions and production, the production separator is connected at the onset of the flowback and stays on after flowback and at the startup of production; in that event, certain reporting and recordkeeping requirements associated with well completions ( e.g., information about when a separator is hooked up or disconnected during flowback) would be unnecessary. 83 FR 52082. Because these amendments to the recordkeeping and reporting requirements associated with well completion are independent of the specific pollutant being regulated, we are proposing these same amendments to the methane standards for well completions in the 2016 NSPS OOOOa.

2. Pneumatic Pumps

In the 2020 Technical Rule, the EPA made certain amendments to the VOC standards for pneumatic pumps in the 2016 NSPS OOOOa. For the same reasons provided in the 2020 Technical Rule, along with further explanation provided below, the EPA is proposing to apply the same amendments to the methane standards for pneumatic pumps in the 2016 NSPS OOOOa.

First, the EPA is proposing to amend the 2016 NSPS OOOOa methane standards for pneumatic pumps to expand the technical infeasibility provision to apply to pneumatic pumps at greenfield sites. Under the 2016 NSPS OOOOa, “emissions from new, modified, and reconstructed natural gas-driven diaphragm pumps located at well sites [must] be reduced by 95 percent if either a control device or the ability to route to a process is already available onsite, unless it is technically infeasible at sites other than new developments ( i.e., greenfield sites).” 81 FR 35824 and 35844. For the 2016 NSPS OOOOa, the EPA concluded that circumstances that could otherwise make control of a pneumatic pump technically infeasible at an existing location could be addressed in the design and construction of a greenfield site. 81 FR 35849 and 35850 (June 3, 2016). Concerns raised in petitions for reconsideration on the 2016 NSPS OOOOa explained that, even at greenfield sites, certain scenarios present circumstances where the control of a pneumatic pump may be technically infeasible despite the site being newly designed and constructed. ¹⁷⁷ These circumstances include, but are not limited to, site designs requiring high-pressure flares to which routing a low-pressure pump discharge is not feasible and use of small boilers or process heaters that are insufficient to control pneumatic pump emissions or that could result in safety trips and burner flame instability. The EPA proposed to extend the technical infeasibility exemption to greenfield sites in 2018 and sought comment on these circumstances that could preclude control of a pneumatic pump at greenfield sites. While the EPA received comments both in favor of and opposing the application of the technical infeasibility exemption to greenfield sites, the commenters did not identify a reasoned basis for the EPA to decline to extend the exemption. See Response to Comments (RTC) for 2020 Technical Rule at 5-1 to 5-4 at Docket ID No. EPA-HQ-OAR-2017-0483. Moreover, the EPA specifically sought information regarding the additional costs that would be incurred if owners and operators of greenfield sites were required to select a control that can accommodate pneumatic pump emissions in addition to the control's primary purpose at a new construction site, but no such information was provided.

¹⁷⁷  See proposal for 2020 Technical Rule at 83 FR 52061.

The 2020 Technical Rule therefore expanded the technical infeasibility provision to apply to pneumatic pumps at all well sites, including new developments (greenfield sites), concluding that the extension was appropriate because the EPA identified circumstances where it may not be technically feasible to control pneumatic pumps at a greenfield site. The 2020 Technical Rule removed the reference to greenfield site in 40 CFR 60.5393a(b) and the associated definition of greenfield site at 40 CFR 60.5430a.

In the final rule preamble for the 2016 NSPS OOOOa, the EPA stated we did not intend to require the installation of a control device at a well site for the sole purpose of controlling emissions from a pneumatic pump, but rather only required control of pneumatic pumps to the extent a control device or process would already be available on site. It is not the EPA's intent to require a greenfield site to install a control device specifically for controlling emissions from a pneumatic pump. It is our understanding that sites are designed to maximize operation and safety. This includes the placement of equipment, such as control devices. Because vented gas from pneumatic pumps is at low pressure, it may not be feasible to move collected gas through a closed vent system to a control device, depending on site design. Therefore, the EPA continues to conclude that, when determining technical feasibility at any site, such a determination should consider the routing of pneumatic pump emissions to the controls which are needed for the other processes at the site ( i.e., not the pneumatic pump). The owner or operator must justify and provide professional or in-house engineering certification for any site where the control of pneumatic pump emissions is technically infeasible. As explained in the RTC for the 2020 Technical Rule, “[t]he EPA believes that the requirement to certify an engineering assessment to demonstrate technical infeasibility provides protection against an owner or operator purposely designing a new site just to avoid routing emissions from a pneumatic pump to an onsite control device or to a process.”  ¹⁷⁸ For the reasons explained above, the EPA is proposing to align the methane standards in the 2016 NSPS OOOOa for controlling pneumatic pump emissions with the amendments made to the VOC standards in the 2020 Technical Rule to allow for a well-justified determination of technical infeasibility at all well sites, including greenfield sites.

¹⁷⁸  See Docket ID No. EPA-HQ-OAR-2017-0483-2291. “For example, consider the example provided by one commenter where a new site design requires only a high-pressure flare to control emergency and maintenance blowdowns and it is not feasible for a low-pressure pneumatic pump discharge to be routed to such a flare. The infeasibility determination would need not only demonstrate that it is not feasible for a low-pressure pneumatic pump discharge to be directly routed to the flare, it would also need to demonstrate that it is infeasible to design and install a low-pressure header to allow routing this discharge to such a flare system.” RTC at 5-4.

Second, the 2020 Technical Rule amended the 2016 NSPS OOOOa to specify that boilers and process heaters are not considered control devices for the purposes of the pneumatic pump standards. It is the EPA's understanding, based on information provided in reconsideration petitions  ¹⁷⁹ submitted regarding the 2016 NSPS OOOOa and comments received on the proposal for the 2020 Technical Rule, that some boilers and process heaters located at well sites are not inherently designed for the control of emissions. While it is true that for some other sources (not pneumatic pumps), boilers and process heaters may be designed as control devices, that is generally not the operational purpose of this equipment at a well site. Instead, it is the EPA's understanding that boilers and process heaters operate seasonally, episodically, or otherwise intermittently as process devices, thus making the use of these devices as controls inefficient and non-compliant with the continuous control requirements at 40 CFR 60.5415a. ¹⁸⁰ Further, as explained in the 2020 Technical Rule, the fact that some boilers and process heaters located at well sites are not inherently designed to control emissions means that “routing pneumatic pump emissions to these devices may result in frequent safety trips and burner flame instability ( e.g., high temperature limit shutdowns and loss of flame signal).” Id. The EPA determined that “requiring the technical infeasibility evaluation for every boiler and process heater located at a wellsite would result in unnecessary administrative burden since each such evaluation would be raising the[se] same concerns.” 85 FR 57404 (September 15, 2020). Further, as described above, the EPA did not intend to require the installation of a control device for the sole purpose of controlling emissions from pneumatic pumps. Based on the EPA's understanding that boilers and process heaters located at well sites are designed and operated as process equipment (meaning they are not inherently designed for the control of emissions), the EPA also does not intend to require their continuous operation solely to control emissions from pneumatic pumps either. Therefore, the EPA is proposing to align the methane standards for pneumatic pumps with the 2020 Technical Rule to specify that boilers and process heaters are not considered control devices for the purposes of controlling pneumatic pump emissions. The EPA solicits comment on this alignment, including whether there are specific examples where boilers and process heaters are currently used as control devices at well sites.

¹⁷⁹  See Docket ID No. EPA-HQ-OAR-2017-0483-0016.

¹⁸⁰  See Docket ID No. EPA-HQ-OAR-2017-0483-0016.

Third, the EPA is proposing to align the certification requirements for the determination that it is technically infeasible to route emissions from a pneumatic pump to a control device or process. The 2016 NSPS OOOOa required certification of technical infeasibility by a qualified third-party Professional Engineer (PE); however, the 2020 Technical Rule allows this certification by either a PE or an in-house engineer, because in-house engineers may be more knowledgeable about site design and control than a third-party PE. The EPA continues to believe that certification by an in-house engineer is appropriate for this purpose. We are, therefore, proposing to align the methane standards in the 2016 NSPS OOOOa with the 2020 Technical Rule to allow certification of technical infeasibility by either a PE or an in-house engineer with expertise on the design and operation of the pneumatic pump. We are soliciting comment on this proposed alignment.

3. Closed Vent Systems (CVS)

As in the 2020 Technical Rule, the EPA is proposing to allow multiple options for demonstrating that there are no detectable methane emissions from CVS. Additionally, the EPA is proposing to allow either a PE or an in-house engineer with expertise on the design and operation of the CVS to certify the design and operation will meet the requirement to route all vapors to the control device or back to the process.

The methane standards in the 2016 NSPS OOOOa require that CVS be operated with no detectable emissions, as demonstrated through specific monitoring requirements associated with the specific affected facilities ( i.e., pneumatic pumps, centrifugal compressors, reciprocating compressors, and storage vessels). Relevant here, the 2016 NSPS OOOOa required this demonstration for both VOC and methane emissions through annual inspections using EPA Method 21 for CVS associated with pneumatic pumps, while requiring storage vessels to conduct monthly audio, visual, olfactory (AVO) monitoring. The 2020 Technical Rule amended the VOC requirements for CVS for pneumatic pumps to align the requirements for pneumatic pumps and storage vessels by incorporating provisions allowing the option to demonstrate the pneumatic pump CVS is operated with no detectable emissions by either an annual inspection using EPA Method 21, monthly AVO monitoring, or OGI monitoring at the frequencies specified for fugitive emissions monitoring. The EPA is proposing to amend the methane standards to allow pneumatic pump affected facilities to permit these same options to demonstrate no detectable methane emissions from CVS either using annual Method 21 monitoring, as currently required by the 2016 NSPS OOOOa, or using either monthly AVO monitoring or OGI monitoring at the fugitive monitoring frequency. The EPA considers these detection options appropriate for CVS associated with pneumatic pumps because any of the three would detect methane as well as VOC emissions. We incorporated the option for monthly AVO monitoring in the 2020 Technical Rule because pneumatic pumps and controlled storage vessels are commonly located at the same site and having separate monitoring requirements for a potentially shared CVS is overly burdensome and duplicative. 83 FR 52083 (October 15, 2018). We further incorporated the option for OGI monitoring because OGI is already being used for those sites that are subject to fugitive emissions monitoring and the CVS can readily be monitored during the fugitive emissions survey at no extra cost. 85 FR 57405. The EPA believes it is appropriate to maintain these options because not all well sites with controlled pneumatic pumps will be subject to fugitive emissions monitoring ( e.g., pneumatic pumps located at existing well sites that have not triggered the fugitive monitoring requirements for new or modified well sites) and requiring either OGI or EPA Method 21 survey of the CVS for the pneumatic pump in the absence of fugitive emissions surveys would be unreasonable. It is possible for a new pneumatic pump to be subject to control at an existing well site that is not subject to the fugitive emissions requirements. Requiring either EPA Method 21 or OGI for the sole purpose of monitoring the CVS associated with the pneumatic pump would be too costly, ¹⁸¹ therefore we continue to believe monthly AVO is an appropriate option for pneumatic pumps subject to the 2016 NSPS OOOOa.

¹⁸¹  Both OGI and EPA Method 21 have significant capital and annual costs, including the cost of specialized equipment and trained operators of that equipment. While the costs of these programs are justified for well site fugitive emission monitoring based on the assumption of a high component count from which emissions would be controlled, the CVS is only one of those many components. Thus, where well site fugitive monitoring is not otherwise required, the cost-effectiveness of OGI or EPA Method 21 would be significantly higher for the CVS alone.

Additionally, the 2020 Technical Rule amended the 2016 NSPS OOOOa to allow certification of the design and operation of CVS by an in-house engineer with expertise on the design and operation of the CVS in lieu of a PE. This certification is necessary to ensure the design and operation of the CVS will meet the requirement to route all vapors to the control device or back to the process. As explained in the proposal for the 2020 Technical Rule, 83 FR 52079, the EPA allows CVS certification by either a PE or an in-house engineer because in-house engineers may be more knowledgeable about site design and control than a third-party PE. For the same reason, the EPA is proposing to amend the CVS requirements associated with methane emissions in the production and processing segments, and methane and VOC emissions in the transmission and storage segment, to allow certification of the design and operation of CVS by either a PE or an in-house engineer with expertise on the design and operation of the CVS.

4. Fugitive Emissions at Well Sites and Compressor Stations

a. Well Sites

The EPA is proposing to exclude from fugitive emissions monitoring a well site that is or later becomes a “wellhead only well site,” which the 2020 Technical Rule defines as “a well site that contains one or more wellheads and no major production and processing equipment.” The 2016 NSPS OOOOa excludes well sites that contain only one or more wellheads from the fugitive emissions requirements because fugitive emissions at such well sites are extremely low. 80 FR 56611. As explained in that rulemaking, “[s]ome well sites, especially in areas with very dry gas or where centralized gathering facilities are used, consist only of one or more wellheads, or `Christmas trees,' and have no ancillary equipment such as storage vessels, closed vent systems, control devices, compressors, separators and pneumatic controllers. Because the magnitude of fugitive emissions depends on how many of each type of component ( e.g., valves, connectors, and pumps) are present, fugitive emissions from these well sites are extremely low.” 80 FR 56611. The 2020 Technical Rule amended the 2016 NSPS OOOOa to exclude from fugitive emissions monitoring a well site that is or later becomes a “wellhead only well site,” which the 2020 Technical Rule defines as “a well site that contains one or more wellheads and no major production and processing equipment.” The 2020 Technical Rule defined “major production and processing equipment” as including reciprocating or centrifugal compressors, glycol dehydrators, heater/treaters, separators, and storage vessels collecting crude oil, condensate, intermediate hydrocarbon liquids, or produced water. We continue to believe that available information, including various studies, ¹⁸² supports an exemption for well sites that do not have this major production and processing equipment. The 2020 Technical Rule allows certain small ancillary equipment, such as chemical injection pumps, pneumatic controllers used to control well emergency shutdown valves, and pumpjacks, that are associated with, or attached to, the wellhead and “Christmas tree” to remain at a “wellhead only well site” without being subject to the fugitive emissions monitoring requirements because they have very few fugitive emissions components that would leak, and therefore have limited potential for fugitive emissions. The emission reduction benefits of continuing monitoring at that point would be relatively low, and thus would not be cost-effective.

¹⁸²  See https://pubs.acs.org/doi/10.1021/acs.est.0c02927, https://data.permianmap.org/pages/flaring, and https://www.edf.org/sites/default/files/documents/PermianMapMethodology_1.pdf.

For the reason stated above, the EPA is proposing to amend the 2016 NSPS OOOOa to allow monitoring of methane fugitive emissions to stop when a wellsite contains only wellhead(s) and no major production and processing equipment, as provided in the 2020 Technical Rule.

b. Compressor Stations

As discussed above, the 2016 NSPS OOOOa required quarterly monitoring of compressor stations for both VOC and methane emissions, and it also permitted waiver from one quarterly monitoring event when the average temperature is below 0 °F for two consecutive months because it is technically infeasible for the OGI camera (and EPA Method 21 instruments) to operate below this temperature. After the 2020 Policy Rule rescinded the methane standards, the 2020 Technical Rule reduced the monitoring requirements for the VOC standards to require only semiannual monitoring and, in doing so, removed the waiver. Upon enactment of the CRA resolution, compressor stations again became subject to quarterly monitoring pursuant to the reinstated 2016 NSPS OOOOa methane standards, and the waiver as it applied to the methane standards was also reinstated. Consistent with our proposal to align the monitoring requirements for VOCs with the monitoring requirements for methane, the EPA is also proposing to reinstate the waiver for the VOC standards as specified in the 2016 NSPS OOOOa.

c. Well Sites and Compressor Stations on the Alaska North Slope

The EPA is proposing to amend the 2016 NSPS OOOOa to require that new, reconstructed, and modified compressor stations located on the Alaska North Slope that startup (initially, or after reconstruction or modification) between September and March to conduct initial monitoring of methane emissions within 6 months of startup, or by June 30, whichever is later. The EPA made a similar amendment to the initial monitoring of methane and VOC emissions at well sites located on the Alaska North Slope in the March 12, 2018 amendments to the 2016 NSPS OOOOa (“2018 NSPS OOOOa Rule”). ¹⁸³ As explained in that action, such separate requirements were warranted due to the area's extreme cold temperatures, which for approximately half of the year are below the temperatures at which the monitoring instruments are designed to operate. The 2020 Technical Rule made this amendment for VOC emissions from gathering and boosting compressor stations located in the Alaska North Slope for this same reason.

¹⁸³  83 FR 10628 (March 12, 2018).

The EPA is also proposing to amend the 2016 NSPS OOOOa to require annual monitoring of methane and VOC emissions at all compressor stations located on the Alaska North Slope, with subsequent annual monitoring at least 9 months apart but no more than 13 months apart. In the 2018 NSPS OOOOa Rule, the EPA similarly amended the monitoring frequency for well sites located on the Alaska North Slope to annual monitoring to accommodate the extreme cold temperature. 83 FR 10628 (March 12, 2018). For the same reason, in the 2020 Technical Rule, the EPA amended the 2016 NSPS OOOOa to require annual VOC monitoring at gathering and boosting compressor stations located on the Alaska North Slope because extreme cold temperatures make it technically infeasible to conduct OGI monitoring for over half of a year. ¹⁸⁴ Because the same difficulties would arise with respect to monitoring for fugitive methane emissions from gathering and boosting compressor stations or to monitoring of methane and VOC emissions from compressor stations in the transmission and storage segment, the EPA is proposing to amend the 2016 NSPS OOOOa to require that all compressor stations located on the Alaska North Slope conduct annual monitoring of both methane and VOC emissions.

¹⁸⁴  See Docket ID Nos. EPA-HQ-OAR-2010-0505-7682 and EPA-HQ-OAR-2010-0505-12434. See also FLIR Systems, Inc. product specifications for GF300/320 model OGI cameras at http://www.flir.com/ogi/display/?id=55671 and Thermo Fisher Scientific product specification for TVA-2020 at https://assets.thermofisher.com/TFS-Assets/LSG/Specification-Sheets/EPM-TVA2020.pdf.

Further, the EPA is proposing to extend the deadline for conducting initial monitoring of both VOC and methane emissions from 60 days to 90 days for all well sites and compressor stations located on the Alaska North Slope that startup or are modified between April and August. In the 2020 Technical Rule, the EPA made this amendment for initial VOC monitoring to allow the well site or gathering and boosting compressor station to reach normal operating conditions. 85 FR 57406. For the same reason, we are proposing to further amend the 2016 NSPS OOOOa to apply this same 90-day initial monitoring requirement to initial monitoring of fugitive methane and VOC emissions from all well sites and compressor stations located on the Alaska North Slope that startup or are modified between April and August.

d. Modification

The 2016 NSPS OOOOa, as originally promulgated, provided that “[f]or purposes of the fugitive emissions standards at 40 CFR 60.5397a, [a] well site also means a separate tank battery surface site collecting crude oil, condensate, intermediate hydrocarbon liquids, or produced water from wells not located at the well site ( e.g., centralized tank batteries).” 40 CFR 60.5430a. However, the original 2016 NSPS OOOOa defined “modification” only with respect to a well site and was silent on what constitutes modification to a well site that is a separate tank battery surface site. Specifically, 40 CFR 60.5365a(i), as promulgated in 2016, specified that, for the purposes of fugitive emissions components at a well site, a modification occurs when (1) a new well is drilled at an existing well site, (2) a well is hydraulically fractured at an existing well site, or (3) a well is hydraulically refractured at an existing well site. See 40 CFR 60.5365a(i).

Because this provision was silent on when modification occurs at a well site that is a separate tank battery surface site, the 2020 Technical Rule added language to clarify that a modification of a well site that is a separate tank battery surface site occurs when (1) any of the actions listed above for well sites occurs at an existing separate tank battery surface site, (2) a well modified as described above sends production to an existing separate tank battery surface site, or (3) a well site subject to the fugitive emissions requirements removes all major production and processing equipment such that it becomes a wellhead-only well site and sends production to an existing separate tank battery surface site. Because the 2020 Technical Rule amended only the VOC standards in the 2016 NSPS OOOOa, and since this definition of modification equally applies to fugitive methane emissions from a separate tank battery surface site, the EPA is proposing to apply this definition of modification for purposes of determining when modification occurs at a separate tank battery surface site triggering the methane standards for fugitive emissions at well sites.

e. Initial Monitoring for Well Sites and Compressor Stations

The 2016 NSPS OOOOa, as originally promulgated, had required monitoring of methane and VOC fugitive emissions at well sites and compressor stations to begin within 60 days of startup (of production in the case of well sites) or modification. The 2020 Technical Rule extended this time frame to 90 days for well sites and gathering and boosting compressor stations in response to comments stating that well sites and compressor stations do not achieve normal operating conditions within the first 60 days of startup and suggesting that the EPA allow 90 days to 180 days. The EPA agreed that additional time to allow the well site or compressor station to reach normal operating conditions is warranted, considering the purpose of the initial monitoring is to identify any issues associated with installation and startup of the well site or compressor station. By providing sufficient time to allow owners and operators to conduct the initial monitoring survey during normal operating conditions, the EPA expects that there will be more opportunity to identify and repair sources of fugitive emissions, whereas a partially operating site may result in missed emissions that remain unrepaired for a longer period of time. 85 FR 57406. These same reasons apply regardless of pollutant or the location of the compressor station; therefore, the EPA is proposing to further amend the 2016 NSPS OOOOa to extend the deadline for conducting initial monitoring from 60 to 90 days for monitoring both VOC and methane fugitive emissions at all well sites and compressor stations (except those on the Alaska North Slope which are separately regulated as discussed in section X.B.4.c).

f. Repair Requirements

The 2020 Technical Rule made certain amendments to the 2016 NSPS OOOOa repair requirements associated with monitoring of fugitive VOC emissions at well sites and gathering and boosting compressor stations. For the same reasons provided in the 2020 Technical Rule and reiterated below, the EPA is proposing to similarly amend the 2016 NSPS OOOOa repair requirements associated with monitoring of methane emissions at well sites and gathering and boosting compressor stations and monitoring of VOC and methane fugitive emissions at compressor stations in the transmission and storage segment.

Specifically, the EPA is proposing to require a first attempt at repair within 30 days of identifying fugitive emissions and final repair, including the resurvey to verify repair, within 30 days of the first attempt at repair. The 2016 NSPS OOOOa, as originally promulgated, required repair within 30 days of identifying fugitive emissions and a resurvey to verify that the repair was successful within 30 days of the repair. Stakeholders raised questions regarding whether emissions identified during the resurvey would result in noncompliance with the repair requirement. In the 2020 Technical Rule, the EPA clarified that repairs should be verified as successful prior to the repair deadline and added definitions for the terms “first attempt at repair” and “repaired.” Specifically, the definition of “repaired” includes the verification of successful repair through a resurvey of the fugitive emissions component. The EPA is similarly proposing to apply these amendments to the repair requirements made in the 2020 Technical Rule to the repair requirements associated with monitoring of methane emissions at well sites and gathering and boosting compressor stations as well as monitoring of VOC and methane fugitive emissions at compressor stations in the transmission and storage segment and monitoring.

In addition, the EPA is proposing that delayed repairs be completed during the “next scheduled compressor station shutdown for maintenance, scheduled well shutdown, scheduled well shut-in, after a scheduled vent blowdown, or within 2 years, whichever is earliest.” The proposed amendment would clarify that completion of delayed repairs is required during scheduled shutdown for maintenance, and not just any shutdown.

In 2018 NSPS OOOOa Rule the EPA amended the 2016 NSPS OOOOa to specify that, where the repair of a fugitive emissions component is “technically infeasible, would require a vent blowdown, a compressor station shutdown, a well shutdown or well shut-in, or would be unsafe to repair during operation of the unit, the repair must be completed during the next scheduled compressor station shutdown, well shutdown, well shut-in, after a planned vent blowdown, or within 2 years, whichever is earlier.”  ¹⁸⁵ During the rulemaking for the 2020 Technical Rule, the EPA received comments expressing concerns with requiring repairs during the next scheduled compressor station shutdown, without regard to whether the shutdown is for maintenance purposes. The commenters stated that repairs must be scheduled and that where a planned shutdown is for reasons other than scheduled maintenance, completion of the repairs during that shutdown may be difficult and disrupt gas transmission. The EPA agrees that requiring the completion of delayed repairs only during those scheduled compressor station shutdowns where maintenance activities are scheduled is reasonable and anticipates that these maintenance shutdowns occur on a regular schedule. Accordingly, in the 2020 Technical Rule the EPA further amended this provision by adding the term “for maintenance” to clarify that repair must be completed during the “next scheduled compressor station shutdown for maintenance” or other specified scheduled events, or within 2 years, whichever is the earliest. For the same reason, the EPA is proposing the same clarifying amendment to the delay of repair requirements for fugitive methane emissions at well sites and gathering and boosting compressor stations and fugitive VOC and methane fugitive emissions at compressor stations in the transmission and storage segment.

¹⁸⁵  83 FR 10638, 40 CFR 60.5397a(h)(2).

g. Definitions Related to Fugitive Emissions at Well Sites and Compressor Stations

The 2020 Technical Rule made certain amendments to the definition of a well site and the definition for startup of production as they relate to fugitive VOC emissions requirements at well sites. For the same reasons provided in the 2020 Technical Rule and reiterated below, the EPA is proposing to similarly amend these definitions as they relate to the fugitive methane emissions requirements at well sites.

The 2020 Technical Rule amended the definition of well site, for purposes of VOC fugitive emissions monitoring, to exclude equipment owned by third parties and oilfield solid waste and wastewater disposal wells. The amended definition for “well site” excludes third party equipment from the fugitive emissions requirements by excluding “the flange immediately upstream of the custody meter assembly and equipment, including fugitive emissions components located downstream of this flange.” To clarify this exclusion, the 2020 Technical Rule defines “custody meter” as “the meter where natural gas or hydrocarbon liquids are measured for sales, transfers, and/or royalty determination,” and the “custody meter assembly” as “an assembly of fugitive emissions components, including the custody meter, valves, flanges, and connectors necessary for the proper operation of the custody meter.” This exclusion was added for several reasons, including consideration that owners and operators may not have access or authority to repair this third-party equipment and because the custody meter “is used effectively as the cash register for the well site and provides a clear separation for the equipment associated with production of the well site, and the equipment associated with putting the gas into the gas gathering system.” 83 FR 52077 (October 15, 2018).

The definition of a well site was also amended in the 2020 Technical Rule to exclude Underground Injection Control (UIC) Class I oilfield disposal wells and UIC Class II oilfield wastewater disposal wells. The EPA had proposed to exclude UIC Class II oilfield wastewater disposal wells because of our understanding that they have negligible fugitive VOC and methane emissions. 83 FR 52077. Comments received on the 2020 Technical rulemaking effort further suggested, and the EPA agreed, that we also should exclude UIC Class I oilfield disposal wells because of their low VOC and methane emissions. Both types of disposal wells are permitted through UIC programs under the Safe Drinking Water Act for protection of underground sources of drinking water. For consistency, the 2020 Technical Rule adopted the definitions for UIC Class I oil field disposal wells and UIC Class II oilfield wastewater disposal wells under the Safe Drinking Water Act definitions in excluding them from the definition of a well site in the 2016 NSPS OOOOa. Specifically, the 2020 Technical Rule defined a UIC Class I oilfield disposal well as “a well with a UIC Class I permit that meets the definition in 40 CFR 144.6(a)(2) and receives eligible fluids from oil and natural gas exploration and production operations.” Additionally, the 2020 Technical Rule defines a UIC Class II oilfield wastewater disposal well as “a well with a UIC Class II permit where wastewater resulting from oil and natural gas production operations is injected into underground porous rock formations not productive of oil or gas, and sealed above and below by unbroken, impermeable strata.” As amended, UIC Class I and UIC Class II disposal wells are not considered well sites for the purposes of VOC fugitive emissions requirements. Because the 2020 Technical Rule, as finalized, addressed only VOC emissions in the production and processing segment, the EPA is proposing the same exclusion and definition of “well site” for the purposes of fugitive emissions monitoring of methane emissions at well sites.

The EPA is also proposing to apply the definition for “startup of production” for purposes of well site fugitive emissions requirements for VOC to these requirements as they relate to methane. The 2016 NSPS OOOOa initially contained a definition for “startup of production” as it relates to the well completion standards that reduce emissions from hydraulically fractured wells. For that purpose, the term was defined as “the beginning of initial flow following the end of flowback when there is continuous recovery of salable quality gas and separation and recovery of any crude oil, condensate or produced water.” 81 FR 25936 (June 3, 2016). The 2020 Technical Rule amended the definition of “startup of production” to separately define the term as it relates to fugitive VOC emissions requirements at well sites. Specifically, “. . .[f]or the purposes of the fugitive monitoring requirements of 40 CFR 60.5397a, startup of production means the beginning of the continuous recovery of salable quality gas and separation and recovery of any crude oil, condensate or produced water” 85 FR 57459 (September 15, 2020). This separate definition clarifies that fugitive emissions monitoring applies to both conventional and unconventional (hydraulically fractured) wells. For this same reason, the EPA is proposing to apply this same definition of “startup of production” to fugitive emissions monitoring of methane emissions at well sites.

h. Monitoring Plan

The 2016 NSPS OOOOa, as originally promulgated, required that each fugitive emissions monitoring plan include a site map and a defined observation path to ensure that the OGI operator visualizes all of the components that must be monitored during each survey. The 2020 Technical Rule amended this requirement to allow the company to specify procedures that would meet this same goal of ensuring every component is monitored during each survey. While the site map and observation path are one way to achieve this, other options can also ensure monitoring, such as an inventory or narrative of the location of each fugitive emissions component. The EPA stated in the 2020 Technical Rule that “these company-defined procedures are consistent with other requirements for procedures in the monitoring plan, such as the requirement for procedures for determining the maximum viewing distance and maintaining this viewing distance during a survey.” 85 FR 57416 (September 15, 2020). Because the same monitoring device is used to monitor both methane and VOC emissions, the same company-defined procedures for ensuring each component is monitored are appropriate. Therefore, the EPA is proposing to similarly amend the monitoring plan requirements for methane and for compressor stations to allow company procedures in lieu of a sitemap and an observation path.

i. Recordkeeping and Reporting

The 2020 Technical Rule amended the 2016 NSPS OOOOa to streamline the recordkeeping and reporting requirements for the VOC fugitive emissions standards. The amendments removed the requirement to report or keep certain records that the EPA determined were redundant or unnecessary; in some instances, the rule replaced those requirements or added new requirements that could better demonstrate and ensure compliance, in particular where the underlying requirement was also amended ( e.g., repair requirements). These amendments reflect consideration of the public comments received on the proposal for that rulemaking. The purpose and function of the recordkeeping and reporting requirements are equally applicable to methane and VOCs, and therefore, are not pollutant specific. For the same reasons the EPA streamlined these requirements in the 2020 Technical Rule, ¹⁸⁶ the EPA is proposing to apply these streamlined recordkeeping and reporting requirements for methane emissions from sources subject to NSPS OOOOa.

¹⁸⁶  See 85 FR 57415 (September 15, 2020).

For each collection of fugitive emissions components located at a well site or compressor station, the following amendments were made to the recordkeeping and reporting requirements in the 2020 Technical Rule:

• Revised the requirements in 40 CFR 60.5397a(d)(1) to require inclusion of procedures that ensure all fugitive emissions components are monitored during each survey within the monitoring plan.

• Removed the requirement to maintain records of a digital photo of each monitoring survey performed, captured from the OGI instrument used for monitoring when leaks are identified during the survey because the records of the leaks provide proof of the survey taking place.

• Removed the requirement to maintain records of the number and type of fugitive emissions components or digital photo of fugitive emissions components that are not repaired during the monitoring survey once repair is completed and verified with a resurvey.

• Required records of the date of first attempt at repair and date of successful repair.

• Revised reporting to specify the type of site ( i.e., well site or compressor station) and when the well site changes status to a wellhead-only well site.

• Removed requirement to report the name or ID of operator performing the monitoring survey.

• Removed requirement to report the number and type of difficult-to-monitor and unsafe-to-monitor components that are monitored during each monitoring survey.

• Removed requirement to report the ambient temperature, sky conditions, and maximum wind speed.

• Removed requirement to report the date of successful repair.

• Removed requirement to report the type of instrument used for resurvey.

5. AMEL

The 2020 Technical Rule made the following amendments to the provisions associated with applications for use of an AMEL for VOC work practice standards for well completions, reciprocating compressors, and the collection of fugitive emissions components located at well sites and gathering and boosting compressor stations. For the same reasons provided in the 2020 Technical Rule and reiterated below, the EPA is proposing to similarly amend the 2016 NSPS OOOOa provisions associated with applications for use of an AMEL for methane work practice standards at well sites and gathering and boosting compressor stations and VOC and methane work practice standards at compressor stations in the transmission and storage segment.

The 2020 Technical Rule amended the AMEL application requirements to help streamline the process for evaluation and possible approval of advanced measurement technologies. The amendments included allowing submission of applications by, among others, owners and operators of affected facilities, manufacturers or vendors of leak detection technologies, or trade associations. The 2020 Technical Rule “allows any person to submit an application for an AMEL under this provision.” 85 FR 57422 (September 15, 2020). However, the 2020 Technical Rule, like the 2016 NSPS OOOOa still requires that the application include sufficient information to demonstrate that the AMEL achieves emission reductions at least equivalent to the work practice standards in the rule. To that end, the 2020 Technical Rule “requires applications for these AMEL to include site-specific information to demonstrate equivalent emissions reductions, as well as site-specific procedures for ensuring continuous compliance.” Id. At a minimum, the application should include field data that encompass seasonal variations, which may be supplemented with modeling analyses, test data, and/or other documentation. The specific work practice(s), including performance methods, quality assurance, the threshold that triggers action, and the mitigation thresholds are also required as part of the AMEL application. For example, for a technology designed to detect fugitive emissions, information such as the detection criteria that indicate fugitive emissions requiring repair, the time to complete repairs, and any methods used to verify successful repair would be required.

Since the 2020 Technical Rule changes to the AMEL provisions in the 2016 NSPS OOOOa are procedural in the sense that they mostly speak to the “minimum information that must be included in each application in order for the EPA to make a determination of equivalency and, thus, be able to approve an alternative” the EPA believes that it is appropriate to retain those amendments. 85 FR 57422 (September 15, 2020). If finalized, the application must demonstrate equivalence as explained above for both the reduction of methane and VOC emissions. Because the 2020 Technical Rule amended only the VOC standards in the 2016 NSPS OOOOa, and since EPA believes that basis for promulgation of this provision for AMEL applications equally applies to work practices standards for methane emissions at facilities in the production and processing segments and VOC and methane emissions at facilities in the transmission and storage segment, the EPA is proposing to apply these application requirements for all applicants seeking an AMEL for the methane and VOC work practice standards in NSPS OOOOa.

6. Alternative Fugitive Emissions Standards Based on Equivalent State Programs

The 2020 Technical Rule added a new section (at 40 CFR 60.5399a) which served two purposes. First, the new section outlined procedures for State, local, and Tribal authorities to seek the EPA's approval of their VOC fugitive emissions standards at well sites and gathering and boosting compressor stations as an alternative to the Federal standards. Second, the new section approved specific voluntary alternative standards for six States. For the same reasons provided in the 2020 Technical Rule and reiterated below, the EPA is proposing to similarly allow this new section to apply to fugitive emissions standards for methane fugitive emissions at well sites and gathering and boosting compressor stations, and VOC and methane fugitive emissions at compressor stations in the transmission and storage segment.

The 2020 Technical Rule added this new section in part to allow the use of specific alternative fugitive emissions standards for VOC emissions for six State fugitive emissions programs that the EPA had concluded were at least equivalent to the fugitive emissions monitoring and repair requirements at 40 CFR 60.5397a(e), (f), (g), and (h) as amended in that rule. ¹⁸⁷ These approved alternative fugitive emissions standards may be used for certain individual well sites or gathering and boosting compressor stations that are subject to VOC fugitive emissions monitoring and repair so long as the source complies with specified Federal requirements applicable to each approved alternative State program and included in 40 CFR 60.5399a(f) through (n). For example, a well site that is subject to the requirements of Pennsylvania General Permit 5A, section G, effective August 8, 2018, could choose to comply with those standards in lieu of the monitoring, repair, recordkeeping, and reporting requirements in the NSPS for fugitive emissions at well sites. However, in that example, the owner or operator must develop and maintain a fugitive emissions monitoring plan, as required in 40 CFR 60.5397a(c) and (d), and must monitor all of the fugitive emissions components, as defined in 40 CFR 60.5430a, regardless of the components that must be monitored under the alternative standard ( i.e., under Pennsylvania General Permit 5A, Section G in the example). Additionally, the facility choosing to use the EPA-approved alternative standard must submit, as an attachment to its annual report for NSPS OOOOa, the report that is submitted to its State in the format submitted to the State, or the information required in the report for NSPS OOOOa if the State report does not include site-level monitoring and repair information. If a well site is located in the State but is not subject to the State requirements for monitoring and repair ( i.e., not obligated to monitor or repair fugitive emissions), then the well site must continue to comply with the Federal requirements of the NSPS at 40 CFR 60.5397a in its entirety.

¹⁸⁷  See memorandum, “Equivalency of State Fugitive Emissions Programs for Well Sites and Compressor Stations to Final Standards at 40 CFR part 60, subpart OOOOa,” located at Docket ID No. EPA-HQ-OAR-2017-0483. January 17, 2020.

In addition to providing the EPA-approved voluntary alternative fugitive emissions standards for well sites and gathering and boosting compressor stations located in California, Colorado, Ohio, Pennsylvania, and Texas, and well sites in Utah, the amendments in the 2020 Technical Rule provide application requirements to request the EPA approval of an alternative fugitive emissions standards as State, local, and Tribal programs continue to develop. Applications for the EPA approval of alternative fugitive emissions standards based on State, local, or Tribal programs may be submitted by any interested person, including individuals, corporations, partnerships, associations, States, or municipalities. Similar to the application process for AMEL for advanced measurement technologies, the application must include sufficient information to demonstrate that the alternative fugitive emissions standards achieve emissions reductions at least equivalent to the fugitive emissions monitoring and repair requirements in the Federal NSPS. At a minimum, the application must include the monitoring instrument, monitoring procedures, monitoring frequency, definition of fugitive emissions requiring repair, repair requirements, recordkeeping, and reporting requirements. If any of the sections of the State regulations or permits approved as alternative fugitive emissions standards are changed at a later date, the State must follow the procedures outlined in 40 CFR 60.5399a to apply for a new evaluation of equivalency.

As part of the 2018 proposed rule (83 FR 52056, October 15, 2018) that resulted in the 2020 Technical Rule, the EPA evaluated the specific State programs for both methane and VOC emissions at well sites, gathering and boosting compressor stations, and compressor stations in the transmission and storage segment as discussed in detail in a memorandum to that docket evaluating the equivalency of State fugitive emissions programs. ¹⁸⁸ The EPA is now proposing that all well sites and compressor stations located in and subject to the specified State regulations in 40 CFR 60.5399a may utilize these alternative fugitive emissions standards for both methane and VOC fugitive emissions. In the 2020 Technical Rule the EPA concluded that these monitoring, repair, recordkeeping, and reporting requirements were equivalent to the same types of requirements in the 2016 NSPS OOOOa for VOC at well sites and gathering and boosting compressor stations. See 85 FR 57424. The monitoring instrument ( i.e., OGI or EPA Method 21) will detect, at the same time, both methane and VOC emissions without speciating these emissions. Therefore, detection of one of these pollutants is also detection of the other pollutant. For the same reasons provided in the 2020 Technical Rule, and explained in the associated State equivalency memos, the EPA proposes to find these same State fugitive emissions standards (as specified in 40 CFR 60.5399a(f) through (n)) equivalent to the specified Federal methane fugitive emissions standards for well sites and gathering and boosting stations, and the methane and VOC fugitive emissions standards for compressor stations in the transmission and storage segment. The EPA is also proposing to allow State, local, and Tribal agencies to apply for the EPA approval of their fugitives monitoring program as an alternative to the Federal NSPS for methane. Put another way, the EPA is proposing to include methane throughout 40 CFR 60.5399a.

¹⁸⁸  See Docket ID Nos. EPA-HQ-OAR-2017-0483-0041 and EPA-HQ-OAR-2017-0483-2277.

The EPA recognizes that the determinations of equivalence included in the 2020 Technical Rule were based on the fugitive emissions monitoring requirements that existed at that time for the 2016 NSPS OOOOa which, based on other changes in the 2020 Technical Rule, included an exemption from monitoring for low production well sites and required semiannual monitoring at gathering and boosting compressor stations. As explained above, the EPA is proposing to repeal both of those changes, and require semiannual monitoring at all well sites, including those with low production, and quarterly monitoring at gathering and boosting compressor stations. These proposed changes to the 2016 NSPS OOOOa fugitive emissions requirements do not impact the EPA's conclusion that the six previously approved alternative State programs are equivalent to the Federal standards. Even so, the EPA is proposing regulatory changes within the alternative State program provisions in 2016 NSPS OOOOa to account for these proposed changes to the Federal standards. See the redline version of regulatory text in the docket at Docket ID No. EPA-HQ-OAR-2021-0317. These changes are intended to ensure that the previously approved alternative State programs continue to maintain equivalency with the Federal standards if NSPS OOOOa is revised as proposed here. With these changes, the EPA continues to find that the alternative State programs that were previously approved are still equivalent with, if not better than, the Federal requirements.

7. Onshore Natural Gas Processing Plants

a. Capital Expenditure

The 2020 Technical Rule made certain amendments to the 2016 NSPS OOOOa definition of capital expenditure as it relates to modifications for VOC LDAR requirements at onshore natural gas processing plants. For the same reasons provided in the 2020 Technical Rule and reiterated below, the EPA is proposing to similarly amend this definition as it relates to the methane LDAR requirements at onshore natural gas processing plants.

The 2020 Technical Rule amended the definition of “capital expenditure” at 40 CFR 50.5430a by replacing the equation used to determine the percent of replacement cost, “Y.” This amendment was necessary because, as originally promulgated, the equation for determining “Y” would result in an error, thus, making it difficult to determine whether a capital expenditure had occurred using the NSPS OOOOa equation. The 2020 Technical Rule replaced the equation with an equation that utilizes the consumer price indices, “CPI” because it more appropriately reflects inflation than the original equation. Specifically, the equation for “Y” as amended in the 2020 Technical Rule, is based on the CPI, where “Y” equals the CPI of the date of construction divided by the most recently available CPI of the date of the project, or “CPI _N /CPI _PD .” Further, the 2020 Technical Rule specifies that the “annual average of the CPI for all urban consumers (CPI-U), U.S. city average, all items” must be used for determining the CPI of the year of construction, and the “CPI-U, U.S. city average, all items” must be used for determining the CPI of the date of the project. This amendment clarified that the comparison of costs is between the original date of construction of the process unit (the affected facility) and the date of the project which adds equipment to the process unit. For these same reasons, the EPA is proposing that the definition of “capital expenditure,” as amended by the 2020 Technical Rule, also be used to determine whether modification had occurred and thus triggers the applicability of the methane LDAR requirements at onshore natural gas processing plants in the 2016 NSPS OOOOa.

b. Initial Compliance Period

The 2020 Technical Rule amended the VOC standards for onshore natural gas processing plants to specify that the initial compliance deadline for the equipment leak standards is 180 days. The EPA is proposing to apply this clarification to the initial compliance deadline with the methane standards for equipment leaks at onshore natural gas processing plants.

As explained in the 2020 Technical Rule, the EPA added a provision requiring compliance “as soon as practicable, but no later than 180 days after initial startup” because that provision was in the NSPS for equipment leaks of VOC at onshore natural gas processing plants when it was first promulgated, specifically at 40 CFR 60.632(a) of part 60, subpart KKK (NSPS KKK). 85 FR 57408. This provision at 40 CFR 60.632(a) provides up to 180 days to come into compliance with NSPS KKK. In 2012, the EPA revised the standards in NSPS KKK with the promulgation of NSPS OOOO  ¹⁸⁹ by lowering the leak definition for valves from 10,000 ppm to 500 ppm and requiring the monitoring of connectors. 77 FR 49490, 49498. While the EPA did not mention that it was also amending the 180-day compliance deadline in NSPS OOOO, this provision at 40 CFR 60.632(a) was not included in NSPS OOOO and, in turn, was not included in NSPS OOOOa. During the rulemaking for NSPS OOOOa, the EPA declined a request to include this provision at 40 CFR 60.632(a) in NSPS OOOOa, explaining that such inclusion was not necessary because NSPS OOOOa already includes by reference a similar provision ( i.e., 40 CFR 60.482-1a(a)) which requires each owner or operator to “demonstrate compliance . . . within 180 days of initial startup,” 80 FR 56593, 56647-8. However, in reassessing the issue during the rulemaking for the 2020 Technical Rule, the EPA noted that NSPS KKK includes both the provision in 40 CFR 60.632(a) and 40 CFR 60.482-1(a), which contains a provision that is the same as the one described above at 40 CFR 60.482-1a(a), thus suggesting that 40 CFR 60.632(a) is not redundant or unnecessary. In fact, the absence of this provision in NSPS OOOO/OOOOa raised a question as to whether compliance is required within 30 days for equipment that is required to be monitored monthly. To clarify this confusion and remain consistent with NSPS KKK, the 2020 Technical Rule amended NSPS OOOOa to reinstate this provision at 40 CFR 60.632(a). For the same reasons explained above, the EPA is proposing to similarly apply this provision to compliance with methane standards for the equipment leaks at onshore natural gas processing plants.

¹⁸⁹  “Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution for Which Construction, Modification or Reconstruction Commenced After August 23, 2011, and on or before September 18, 2015.”

This provision clarifies that monitoring must begin as soon as practicable, but no later than 180 days after the initial startup of a new, modified, or reconstructed process unit at an onshore natural gas processing plant. Once started, monitoring must continue with the required schedule. For example, if pumps are monitored by month 3 of the initial startup period, then monthly monitoring is required from that point forward. This initial compliance period is different than the compliance requirements for newly added pumps and valves within a process unit that is already subject to a LDAR program. Initial monitoring for those newly added pumps and valves is required within 30 days of the startup of the pump or valve ( i.e., when the equipment is first in VOC service).

8. Technical Corrections and Clarifications

The 2020 Technical Rule also revised the 2016 NSPS OOOOa for VOC emissions to include certain additional technical corrections and clarifications. In this action, the EPA is proposing to apply these same technical corrections and clarifications to the methane standards for production and processing segments and/or the methane and VOC standards for the transmission and storage segment in the 2016 NSPS OOOOa, as appropriate. Specifically, the EPA is proposing to:

• Revise 40 CFR 60.5385a(a)(1), 60.5410a(c)(1), 60.5415a(c)(1), and 60.5420a(b)(4)(i) and (c)(3)(i) to clarify that hours or months of operation at reciprocating compressor facilities must be measured beginning with the date of initial startup, the effective date of the requirement (August 2, 2016), or the last rod packing replacement, whichever is latest.

• Revise 40 CFR 60.5393a(b)(3)(ii) to correctly cross-reference paragraph (b)(3)(i) of that section.

• Revise 40 CFR 60.5397a(c)(8) to clarify the calibration requirements when Method 21 of appendix A-7 to part 60 is used for fugitive emissions monitoring.

• Revise 40 CFR 60.5397a(d)(3) to correctly cross-reference paragraphs (g)(3) and (4) of that section.

• Revise 40 CFR 60.5401a(e) to remove the word “routine” to clarify that pumps in light liquid service, valves in gas/vapor service and light liquid service, and pressure relief devices (PRDs) in gas/vapor service within a process unit at an onshore natural gas processing plant located on the Alaska North Slope are not subject to any monitoring requirements, whether the monitoring is routine or nonroutine.

• Revise 40 CFR 60.5410a(e) to correctly reference pneumatic pump affected facilities located at a well site as opposed to pneumatic pump affected facilities not located at a natural gas processing plant (which would include those not at a well site). This correction reflects that the 2016 NSPS OOOOa do not contain standards for pneumatic pumps at gathering and boosting compressor stations. 81 FR 35850.

• Revise 40 CFR 60.5411a(a)(1) to remove the reference to paragraphs (a) and (c) of 40 CFR 60.5412a for reciprocating compressor affected facilities.

• Revise 40 CFR 60.5411a(d)(1) to remove the reference to storage vessels, as this paragraph applies to all the sources listed in 40 CFR 60.5411a(d), not only storage vessels.

• Revise 40 CFR 60.5412a(a)(1) and (d)(1)(iv) to clarify that all boilers and process heaters used as control devices on centrifugal compressors and storage vessels must introduce the vent stream into the flame zone. Additionally, revise 40 CFR 60.5412a(a)(1)(iv) and (d)(1)(iv)(D) to clarify that the vent stream must be introduced with the primary fuel or as the primary fuel to meet the performance requirement option. This is consistent with the performance testing exemption in 40 CFR 60.5413a and continuous monitoring exemption in 40 CFR 60.5417a for boilers and process heaters that introduce the vent stream with the primary fuel or as the primary fuel.

• Revise 40 CFR 60.5412a(c) to correctly reference both paragraphs (c)(1) and (2) of that section, for managing carbon in a carbon adsorption system.

• Revise 40 CFR 60.5413a(d)(5)(i) to reference fused silica-coated stainless steel evacuated canisters instead of a specific name brand product.

• Revise 40 CFR 60.5413a(d)(9)(iii) to clarify the basis for the total hydrocarbon span for the alternative range is propane, just as the basis for the recommended total hydrocarbon span is propane.

• Revise 40 CFR 60.5413a(d)(12) to clarify that all data elements must be submitted for each test run.

• Revise 40 CFR 60.5415a(b)(3) to reference all applicable reporting and recordkeeping requirements.

• Revise 40 CFR 60.5416a(a)(4) to correctly cross-reference 40 CFR 60.5411a(a)(3)(ii).

• Revise 40 CFR 60.5417a(a) to clarify requirements for controls not specifically listed in paragraph (d) of that section.

• Revise 40 CFR 60.5422a(b) to correctly cross-reference 40 CFR 60.487a(b)(1) through (3) and (b)(5).

• Revise 40 CFR 60.5422a(c) to correctly cross-reference 40 CFR 60.487a(c)(2)(i) through (iv) and (c)(2)(vii) through (viii).

• Revise 40 CFR 60.5423a(b) to simplify the reporting language and clarify what data are required in the report of excess emissions for sweetening unit affected facilities.

• Revise 40 CFR 60.5430a to remove the phrase “including but not limited to” from the “fugitive emissions component” definition. During the 2016 NSPS OOOOa rulemaking, the EPA stated in a response to comment that this phrase is being removed, ¹⁹⁰ but did not do so in that rulemaking.

¹⁹⁰  See Docket ID Item No. EPA-HQ-OAR-2010-0505-7632, Chapter 4, page 4-319.

• Revise 40 CFR 60.5430a to remove the phrase “at the sales meter” from the “low pressure well” definition to clarify that when determining the low-pressure status of a well, pressure is measured within the flow line, rather than at the sales meter.

• Revise Table 3 of 40 CFR part 60, subpart OOOOa, to correctly indicate that the performance tests in 40 CFR 60.8 do not apply to pneumatic pump affected facilities.

• Revise Table 3 of 40 CFR part 60, subpart OOOOa, to include the collection of fugitive emissions components at a well site and the collection of fugitive emissions components at a compressor station in the list of exclusions for notification of reconstruction.

• Revise 40 CFR 60.5393a(f), 60.5410a(e)(8), 60.5411a(e), 60.5415a(b) introductory text and (b)(4), 60.5416a(d), and 60.5420a(b) introductory text and (b)(13), and introductory text in 40 CFR 60.5411a and 60.5416a, to remove language associated with the administrative stay we issued under section 307(d)(7)(B) of the CAA in “Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources; Grant of Reconsideration and Partial Stay” (82 FR 25730, June 5, 2017). The administrative stay was vacated by the D.C. Circuit on July 3, 2017.

XI. Summary of Proposed NSPS OOOOb and EG OOOOc

This section presents a summary of the specific NSPS standards and EG presumptive standards the EPA is proposing for various types of equipment and emission points. More details of the rationale for these standards and requirements, including alternative compliance options and exemptions to the standards, are provided in section XII of this preamble and the TSD for this action in the public docket. As stated in section I, the EPA intends to provide draft regulatory text for the proposed NSPS OOOOb and EG OOOOc in a supplemental proposal.

A. Fugitive Emissions From Well Sites and Compressor Stations

Fugitive emissions are unintended emissions that can occur from a range of equipment at any time. The magnitude of these emissions can also vary widely. The EPA has historically targeted fugitive emissions from the Crude Oil and Natural Gas source category through ground-based component level monitoring using OGI, or alternatively, EPA Method 21.

The EPA is proposing the following monitoring requirements and presumptive standards for the collection of fugitive emissions components located at well sites and compressor stations. Additional details for the proposed standards and proposed presumptive standards are included in the following subsections. Information received through the various solicitations in this section may be used to evaluate if a change in the BSER is appropriate from the proposed requirements below, specifically consideration of alternative measurement technologies as the BSER. Any potential changes would be addressed through a supplemental proposal.

• Well sites with total site-level baseline methane emissions less than 3 tpy: Demonstration, based on a site-specific survey, that actual emissions are reflected in the baseline methane emissions calculation,

• Well sites with total site-level baseline methane emissions of 3 tpy or greater: Quarterly OGI or EPA Method 21 monitoring,

• (Co-proposal) Well sites with total site-level baseline methane emissions of 3 tpy or greater and less than 8 tpy: Semiannual OGI or EPA Method 21 monitoring,

• (Co-proposal) Well sites with total site-level baseline methane emissions of 8 tpy or greater: Quarterly OGI or EPA Method 21 monitoring,

• Compressor stations: Quarterly OGI or EPA Method 21 monitoring,

• Well sites and compressor stations located on the Alaska North Slope: Annual monitoring, with separate initial monitoring requirements, and

• Alternative screening approach for all well sites and compressor stations: Bimonthly screening surveys using advanced measurement technology and annual OGI or EPA Method 21 monitoring at each individual well site or compressor station.

1. Definition of Fugitive Emissions Component

A key factor in evaluating how to target fugitive emissions is clearly identifying the emissions of concern and the sources of those emissions. In the 2016 NSPS OOOOa, the EPA defined “fugitive emissions component” as “any component with the potential to emit methane and VOCs” and included several specific component types, ranging from valves and connectors, to openings on controlled storage vessels that were not regulated under NSPS OOOOa.

However, data shows that the universe of components with potential for fugitive emissions is broader than the illustrative list included in the 2016 NSPS OOOOa, and that the majority of the largest emissions events occur from a subset of components that may not have been clearly included in the definition. Therefore, the EPA is proposing a new definition for “fugitive emissions component” to provide clarity that these sources of large emission events are covered.

“Fugitive emissions component” is proposed to be any component that has the potential to emit fugitive emissions of methane and VOC at a well site or compressor station, including valves, connectors, PRDs, open-ended lines, flanges, all covers and closed vent systems, all thief hatches or other openings on a controlled storage vessel, compressors, instruments, meters, natural gas-driven pneumatic controllers or natural gas-driven pumps. However, natural gas discharged from natural gas-driven pneumatic controllers or natural gas-driven pumps are not considered fugitive emissions if the device is operating properly and in accordance with manufacturers specifications. Control devices, including flares, with emissions resulting from the device operating in a manner that is not in full compliance with any Federal rule, State rule, or permit, are also considered fugitive emissions components. This proposed definition includes the same components that were included in the 2016 NSPS OOOOa and adds sources of large emissions, such as malfunctioning controllers or control devices.

The inclusion of specific component types in this proposed definition would allow the use of OGI, EPA Method 21, or an alternative screening technology to identify emissions that would either be repaired ( i.e., leaks) or have a root cause analysis with corrective action ( e.g., malfunctioning control device, unintentional gas carry through, venting from covers and openings on a controlled storage vessel, or malfunctioning natural gas-driven pneumatic controllers). Further, we are proposing that where a CVS is used to route emissions from an affected facility ( i.e., centrifugal or reciprocating compressor, pneumatic pump, or storage vessel), the owner or operator would demonstrate there are no detectable emissions from the covers and CVS through the OGI (or EPA Method 21) monitoring conducted during the fugitive emissions survey. Where emissions are detected, corrective actions to complete all necessary repairs as soon as practicable would be required, and the emissions would be considered a potential violation of the no detectable emissions standard. In the case of a malfunction or operational upset of a control device or the equipment itself, where emissions are not expected to occur if the equipment is operating in compliance with the standards of the rule, this proposal would require the owner or operator to conduct a root cause analysis to determine why the emissions are present, take corrective action to complete all necessary repairs as soon as practicable and prevent reoccurrence of emissions, and report the malfunction or operational upset as a potential violation of the underlying standards for the source of the emissions. We are soliciting comment on whether to include the option to continue utilizing monthly AVO surveys as demonstrations of no detectable emissions from a CVS but are not proposing that option specifically. Because the EPA is proposing both NSPS and EG in this action, we anticipate that CVS associated with controlled pneumatic pumps will be located at well sites subject to fugitive emissions monitoring. Therefore, we do not believe the monthly AVO option is necessary. However, we are soliciting comment on whether there are circumstances where a CVS associated with a controlled pneumatic pump is located at a well site not otherwise subject to fugitive emissions monitoring and where OGI (or EPA Method 21) would be an additional burden.

The EPA is soliciting comment on this proposed definition of “fugitive emissions component,” including any additional components or characterization of components that should be included. Further, we are soliciting comment on the use of the fugitive emissions survey to identify malfunctions and other large emission sources where the equipment is not operating in compliance with the underlying standards, including the proposed requirement to perform a root cause analysis and to take corrective action to mitigate and prevent future malfunctions.

2. Fugitive Emissions From Well Sites

The current NSPS for reducing fugitive VOC and methane emissions at well sites requires semiannual monitoring, except that a low production well site (one that produces at or below 15 barrels of oil equivalent (boe) per day) is exempt from VOC monitoring. As explained in section X.A.1, we are proposing to remove that exemption from NSPS OOOOa, as we have concluded that exemption was not justified by the underlying record and does not represent BSER. Further, based on our revised BSER analysis, which is summarized in section XII.A.1.a, the EPA is proposing updated standards for reducing fugitive VOC and methane emissions from the collection of fugitive emissions components located at new, modified, or reconstructed well sites (under the newly proposed NSPS OOOOb). Also, for the reasons discussed in section XII.A.2, the EPA is proposing to determine that the BSER analysis supports a presumptive standard for reducing methane emissions from the collection of fugitive emissions components located at existing well sites (under the newly proposed EG OOOOc) that is the same as what we are proposing for the NSPS (for NSPS OOOOb). Provided below is a summary of the proposed updated NSPS and the proposed EG.

a. NSPS OOOOb

For new, modified, or reconstructed sources, we are proposing a fugitive emissions monitoring and repair program that includes monitoring for fugitive emissions with OGI in accordance with the proposed 40 CFR part 60, appendix K (“appendix K”), which is included in this action and outlines the proposed procedures that must be followed to identify emissions using OGI. ¹⁹¹ We are also proposing that EPA Method 21 may be used as an alternative to OGI monitoring. We are further proposing that monitoring must begin within 90 days of startup of production (or startup of production after modification).

¹⁹¹  “Determination of Volatile Organic Compound and Greenhouse Gas Leaks Using Optical Gas Imaging” located at Docket ID No. EPA-HQ-OAR-2021-0317.

Unlike in NSPS OOOOa which, as amended by the 2020 Technical Rule, set VOC monitoring frequency based on production level, the EPA is proposing that the OGI monitoring frequency be based on the site-level methane baseline emissions, ¹⁹² as determined, in part, through equipment/component count emission factors. The EPA is proposing the calculation of the total site-wide methane emissions, including fugitive emissions from components, emissions from natural gas-driven pneumatic controllers, natural gas-driven pneumatic pumps, storage vessels, as well as other regulated and non-regulated emission sources. Specifically, we are proposing that owners or operators would calculate the site-level baseline methane emissions using a combination of population-based emission factors and storage vessel emissions. Further, the EPA proposes this calculation would be repeated every time equipment is added to or removed from the site. For each natural gas-driven pneumatic pump, continuous bleed natural gas-driven pneumatic controller, and intermittent bleed natural gas-driven pneumatic controller located at the well site, the owner or operator would apply the population emission factors for all components found in Table W-1A of GHGRP subpart W. For each piece of major production and processing equipment and each wellhead located at the well site, the owner or operator would first apply the default average component counts for major equipment found in Table W-1B and Table W-1C of GHGRP subpart W, and then apply the component-type emission factors for the population of valves, connectors, open-ended lines, and PRVs found in Table 2-8 of the 1995 Emissions Protocol. ¹⁹³ Finally, the owner or operator would use the calculated potential methane emissions after applying control (if applicable) for each storage vessel tank battery located at the well site. The sum of the emissions estimated for all equipment at the site would be used as the baseline methane emissions for determining the applicable monitoring frequency. The EPA proposes to use the default population emission factors found in Table W-1A of GHGRP subpart W and the default average component counts for major equipment found in Tables W-1B and W-1C of GHGRP subpart W because they are well-vetted emission and activity factors used by the Agency. The EPA is not incorporating these emission factors directly into the proposed NSPS OOOOb or EG OOOOc because they could be the subject of future GHGRP subpart W revisions, and if revised, those revisions would be relevant to this calculation. For the individual components ( e.g., valves and connectors), the EPA proposes to rely on the component-type emission factors found in Table 2-8 of the 1995 Emissions Protocol for purposes of quantifying emissions from major production and processing equipment and each wellhead located at the well site because these data have been relied upon in previous rulemakings for this sector, have been the subject of extensive public comment, and the EPA has determined that they are appropriate to use for purposes of this action.

¹⁹²  As shown in the TSD, the EPA analyzed the monitoring frequency for both methane and VOC under both the single pollutant approach and the multipollutant approach. Because the composition of gas at a well site is predominantly methane (approximately 70 percent), a methane threshold represents the lowest threshold that is cost effective to control both VOC and methane emissions.

¹⁹³  EPA, Protocol for Equipment Leak Emission Estimates, EPA-453/R-95-017, November 1995.

The EPA requests comment on whether the proposed methodologies for calculating site-level baseline methane emissions are appropriate for these emission sources, and if not, what methodologies would be more appropriate. Specifically, the EPA recognizes the proposed calculation methodology assumes all equipment is operating as designed ( e.g., controlled storage vessels with all vapors routed to a control that is actually achieving 95 percent reduction or greater). Therefore, we are soliciting comment on whether sites should use the uncontrolled PTE calculation for their storage vessels in their site-level baseline estimate to account for times when these vessels are not operating as designed, which is a known cause of large emission events of concern. Further, to that point, the EPA is soliciting comment on how to develop a factor that could be applied to the site-level baseline calculation that would account for large emission events, or any specific data that would provide a factor for these events. As we state throughout this preamble, large emission events are of specific concern and fugitive emissions monitoring is an effective tool for detecting these emissions, therefore, we acknowledge there is considerable interest from various stakeholders that these emission events are accounted for in our analyses. At this time, the EPA does not have enough information to develop a factor or determine how to best apply that factor. Information provided through this solicitation would allow us to consider additional revisions to this calculation methodology through a supplemental proposal.

The EPA is also soliciting comment on whether providing direct major equipment population emission factors that can be combined with site-specific gas compositions would provide a more transparent and less burdensome means to develop the site-specific emissions estimates than using a combination of major equipment counts, specific component counts per major equipment, and component-level population emission factors. Furthermore, the EPA requests comment on whether site-level baseline methane emissions should be determined using a baseline emissions survey instead of the proposed methodology, and if so, what methodologies should be used to quantify emissions from the survey such as measurement or emission factors based on leaking component emission factors. The EPA also solicits comment on specific methodologies to support commenters' positions. The EPA also requests comment on whether there are additional production and processing equipment or emission sources that should be included in the site-level baseline methane emissions. For example, the EPA is aware that there could be emission sources such as engines, dehydrator venting, compressor venting, associated gas venting, and migration of gas outside of the wellbore at a well site. If such equipment or emission sources should be included in the site-level baseline, the EPA requests comment on methodologies for quantifying emissions for purposes of the baseline.

Based on the analysis described in section XII.A.1, the potential for fugitive emissions is impacted more by the number and type of equipment at the site, and not by the volume of production. Therefore, the EPA believes it is more appropriate to use site-specific emissions estimates based on the number and type of equipment located at the individual site to determine the monitoring frequency. Table 13 summarizes the proposed site-level baseline methane thresholds for the proposed monitoring frequencies, which according to our analysis would achieve the greatest cost-effective emission reductions.

As noted below, the EPA solicits comment on all aspects of the proposed tiered approach to monitoring that is summarized in Table 13. Although we are proposing no routine OGI monitoring where site-level baseline methane emissions are below 3 tpy, the EPA is proposing to require these sites to demonstrate the actual emissions are accounted for in the calculation. This demonstration would include a survey, such as OGI, EPA Method 21 (including provisions for the use of a soap solution), or advanced measurement technologies. Given that this demonstration is designed to show actual emissions are below 3 tpy, and most survey techniques are not quantitative, the EPA anticipates that sources finding emissions will make repairs on equipment/components identified as leaking during the demonstration survey.

The EPA acknowledges that the 2016 NSPS OOOOa and this proposal allow the use of EPA Method 21 as an alternative to OGI monitoring to detect fugitive emissions from the collection of fugitive emissions components under the proposed tiered approach to monitoring. However, as discussed in section XI.A.5, EPA Method 21 is not proposed as an alternative for follow-up OGI surveys under the proposed alternative screening approach using advanced measurement technologies when screening detects emissions. This is because EPA Method 21 is not able to find all sources of leaks and is therefore not an appropriate method for detection in these cases where large emissions events have been identified. Given this limitation, the EPA is soliciting comment on whether EPA Method 21 remains an appropriate alternative to OGI for routine OGI surveys.

Where quarterly monitoring is proposed, subsequent quarterly monitoring would occur at least 60 days apart. Where semiannual monitoring is co-proposed, subsequent semiannual monitoring would occur at least 4 months apart and no more than 7 months apart. We are proposing to retain the provision in the 2016 NSPS OOOOa that the quarterly monitoring may be waived when temperatures are below 0 °F for two of three consecutive calendar months of a quarterly monitoring period.

The EPA has previously required the use of OGI technology to detect fugitive emissions of methane and VOC from the oil and gas sector ( i.e., well sites and compressor stations). However, the EPA had not developed a protocol for its use even though the EPA has previously mentioned the need for an OGI protocol during other rulemakings where OGI has been proposed for leak detection. ¹⁹⁴ In this document, the EPA is proposing a draft protocol for the use of OGI as appendix K to 40 CFR part 60. The EPA notes that while this protocol is being proposed for use in the oil and gas sector, the applicability of the protocol is broader. The protocol is applicable to surveys of process equipment using OGI cameras in the entire oil and gas upstream and downstream sectors from production to refining to distribution where a subpart in those sectors references its use.

¹⁹⁴  The development of appendix K to 40 CFR part 60 was previously mentioned in both the proposal for the National Uniform Emission Standards for Storage Vessel and Transfer Operations, Equipment Leaks, and Closed Vent Systems and Control Devices; and Revisions to the National Uniform Emission Standards General Provisions (77 FR 17897, March 26, 2012) and the Petroleum Refinery Sector Risk and Technology Review and New Source Performance Standards (79 FR 36880, June 30, 2014).

As part of the development of appendix K, the EPA conducted an extensive literature review on the technology development as well as observations on current application of OGI technology. Approximately 150 references identify the technology, applications, and limitations of OGI. The EPA also commissioned multiple laboratory studies and OGI technology evaluations. Additionally, on November 9 and 10, 2020, the EPA held a virtual stakeholder workshop to gather input on development of a protocol for the use of OGI. The information obtained from these efforts was used to develop the TSD for appendix K, which provides technical analyses, experimental results, and other supplemental information used to evaluate and develop standardized procedures for the use of OGI technology in monitoring for fugitive emissions of VOCs, HAP, and methane from industrial environments. ¹⁹⁵

¹⁹⁵   Technical Support Document—Optical Gas Imaging Protocol (40 CFR part 60, Appendix K), available in the docket for this action.

Appendix K outlines the proposed procedures that instrument operators must follow to identify leaks or fugitive emissions using a hand-held, field portable infrared camera. Additionally, appendix K contains proposed specifications relating to the required performance of qualifying infrared cameras, required operator training and verification, determination of an operating window for performing surveys, and requirements for a monitoring plan and recordkeeping. The EPA is requesting comment on all aspects of the draft OGI protocol being proposed as appendix K to 40 CFR part 60. ¹⁹⁶

¹⁹⁶  See appendix K in Docket ID No. EPA-HQ-OAR-2021-0317.

As mentioned in section X.B.4.f, we are proposing that, once fugitive methane emissions are detected during the OGI survey, a first attempt at repair must be made within 30 days of detecting the fugitive emissions, with final repair, including resurvey to verify repair, completed within 30 days after the first attempt. These proposed repair requirements with respect to methane fugitive emissions are the same as those made in the 2020 Technical Rule for VOC fugitive emissions (and proposed in section X.B.4.f for methane in this action). Because large emission events contribute disproportionately to emissions, the EPA is soliciting comment on how to structure a requirement that would tier repair deadlines based on the severity of the fugitive emissions identified during the OGI (or EPA Method 21) surveys. In order for such a structure to work, there would need to be a way to qualify which fugitive emissions are smaller and which are larger, as the initial monitoring with OGI will not provide this information. One approach could be to define broad categories of leaks and make assumptions about the magnitude of emissions for those broad categories. For example, an open thief hatch would be considered a very large leak due to the surface opening size, and it would need to be remedied on the tightest timeframe, whereas a leaking connector would be considered a small leak based on historical emissions factors and could be repaired on a more lenient timeframe. The EPA is soliciting comments on how this approach could be structured, particularly the types of leaks that would fall into each broad category and the appropriate repair timeframes for each of the categories. The EPA is also soliciting comment on other approaches that could also be implemented for repairing fugitive emissions in a tiered structure. Finally, we are proposing to retain the requirement for owners and operators to develop a fugitive emissions monitoring plan that covers all the applicable requirements for the collection of fugitive emissions components located at a well site and includes the elements specified in the proposed appendix K when using OGI.

The affected facilities include well sites with major production and processing equipment, and centralized tank batteries. As in the 2020 Technical Rule, the EPA is proposing to not include “wellhead only well sites,” as affected facilities when the well site is a wellhead only well site at the date it becomes subject to the rule. Based on the proposed site-level baseline methane emissions calculation methodology, wellhead only sites would only calculate emissions from fugitive components ( e.g., valves, connectors, flanges, and open-ended lines) that are located on the wellhead. We believe these sites would not exceed the 3 tpy threshold to require routine monitoring. However, unlike the 2020 Technical Rule, the EPA is proposing that when a well site later removes all major production and processing equipment such that it becomes a wellhead only well site, it must recalculate the emissions in order to determine if a different frequency is then required. In this proposal, the definitions for “wellhead only well site” and “well site” would be the same as those finalized in the 2020 Technical Rule. Specifically, “wellhead only well site” means “for purposes of the fugitive emissions standards, a well site that contains one or more wellheads and no major production and processing equipment.” The term “major production and processing equipment” refers to “reciprocating or centrifugal compressors, glycol dehydrators, heater/treaters, separators, and storage vessels collecting crude oil, condensate, intermediate hydrocarbon liquids, or produced water.” The EPA is soliciting comment on whether any other equipment not included in this definition should be added in order to clearly specify what well sites are considered wellhead only sites. Specifically, the EPA is soliciting comment on the inclusion of natural gas-driven pneumatic controllers, natural gas-driven pneumatic pumps, and pumpjack engines in the definition of “major production and processing equipment.” A “well site” means one or more surface sites that are constructed for the drilling and subsequent operation of any oil well, natural gas well, or injection well. For purposes of the fugitive emissions standards, a well site includes a centralized production facility. Also, for purposes of the fugitive emissions standards, a well site does not include: (1) UIC Class II oilfield disposal wells and disposal facilities; (2) UIC Class I oilfield disposal wells; and (3) the flange immediately upstream of the custody meter assembly and equipment, including fugitive emissions components, located downstream of this flange.

In addition to retaining the above definitions, the EPA is also proposing a new definition for “centralized production facility” for purposes of fugitive emissions requirements for well sites, where a “centralized tank battery” is one or more permanent storage tanks and all equipment at a single stationary source 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. Additional discussion on centralized production facilities is included in section XI.L.

The EPA is not proposing any change to the current definition of modification as it relates to fugitive emissions requirements at well sites or centralized production facilities. Specifically, modification occurs at a well site when: (1) A new well is drilled at an existing well site; (2) a well at an existing well site is hydraulically fractured; or (3) a well at an existing well site is hydraulically refractured. Similarly, modification occurs at a centralized production facility when (1) any of the actions above occur at an existing centralized production facility; (2) a well sending production to an existing centralized production facility is modified as defined above for well sites; or (3) a well site subject to the fugitive emissions standards for new sources removes all major production and processing equipment such that it becomes a wellhead only well site and sends production to an existing centralized production facility.

b. EG OOOOc

For existing well sites (for EG OOOOc), we are proposing a presumptive standard that follows the same fugitive monitoring and repair program as for new sources. For the reasons discussed in section XII.A.2, the BSER analysis for existing sources supports proposing a presumptive standard for reducing methane emissions from the collection of fugitive emissions components located at existing well sites that is the same as what the EPA is proposing for new, reconstructed, or modified sources (for NSPS OOOOb). The EPA did not identify any factors specific to existing sources that would alter the analysis performed for new sources to make that analysis different for existing well sites. The EPA determined that the OGI technology, methane emission reductions, costs, and cost effectiveness discussed above for the collection of fugitive emissions components at new well sites are also applicable for the collection of fugitive emissions components at existing well sites. Further, the fugitive emissions requirements do not require the installation of controls on existing equipment or the retrofit of equipment, which can generally be an additional factor for consideration when determining the BSER for existing sources. Therefore, the EPA found is appropriate to use the analysis developed for the proposed NSPS OOOOb to also develop the BSER and proposed presumptive standards for the EG OOOOc.

Based on the information available at this time, the EPA thinks the large number of existing well sites, many of which are not complex warrants soliciting comment on whether existing well sites (or a subcategory thereof) could have different emission profiles due to certain site characteristics or other factors that would suggest a different presumptive standard is appropriate. Further, we remain concerned about the burden of fugitive emissions monitoring requirements on small businesses. Therefore, we are requesting comment on regulatory alternatives for well sites that accomplish the stated objectives of the CAA and which minimize any significant economic impact of the proposed rule on small entities, including any information or data that pertain to the emissions impacts and costs of our proposal to remove the exemption from fugitive monitoring for well sites with low emissions, or would support alternative fugitive monitoring requirements for these sites. We are soliciting data that assess the emissions from low production well sites, and information on any factors that could make certain well sites less likely to emit VOC and methane, including geologic features, equipment onsite, production levels, and any other factors that could establish the basis for appropriate regulatory alternatives for these sites. Further, the EPA is aware there are a subset of existing well sites that are owned by individual homeowners, farmers, or companies with very few employees (well below the threshold defining a small business). For these owners, the EPA is concerned our analysis underestimates the actual burden imposed by these proposed standards. As an example, ownership may be limited to 1 or 2 wells located on an individual's property, for which the production is used for heating the home. The cost burden of conducting fugitive emissions surveys in this type of scenario has not fully be analyzed. Therefore, the EPA solicits comment and information that would allow us to further evaluate the burden on the smallest companies to further propose appropriate standards at this subset (or other similar subsets) of well sites through a supplemental proposal.

Finally, we are soliciting comment on all aspects of the proposed fugitive emissions requirements for both new and existing well sites, including whether we should use the tiering approach, whether the tiers we have defined are appropriate, and the monitoring requirements for each tier, including whether it would be cost-effective to monitor at more frequent intervals than proposed. The EPA may include revisions to this proposal for ground-based OGI monitoring at well sites if information is received that would warrant consideration of a different approach to establishing monitoring frequencies at well sites.

3. Fugitive Emissions from Compressor Stations

The current NSPS for reducing fugitive emissions from the collection of fugitive emissions components located at a compressor station is a fugitive emissions monitoring and repair program requiring quarterly OGI monitoring. ¹⁹⁷ Based on our analysis, which is summarized in section XII.A.1.b, the EPA is proposing quarterly OGI monitoring requirement for both methane and VOC as it continues to reflect the BSER for reducing both emissions from fugitive components at new, modified, and reconstructed compressor stations. Likewise, the EPA is also proposing quarterly monitoring as a presumptive GHG standard (in the form of limitation on methane emissions) for the collection of fugitive emissions components located at existing compressor stations. The affected compressor stations include gathering and boosting, transmission, and storage compressor stations.

¹⁹⁷  Note that for gathering and boosting compressor stations, the EPA is proposing to rescind the 2020 Technical Rule amendment that changed the monitoring frequency to semiannual for VOC emissions. See section X.A.2 for more information.

a. NSPS OOOOb

We are proposing that the quarterly monitoring using OGI be conducted in accordance with the proposed appendix K described above in section XI.A.2, which outlines procedures that must be followed to identify leaks using OGI. We are proposing to retain the current requirements that monitoring must begin within 90 days of startup of the station (or startup after modification), with subsequent quarterly monitoring occurring at least 60 days apart. Also, quarterly monitoring may be waived when temperatures are below 0 °F for two of three consecutive calendar months of a quarterly monitoring period. We are also not proposing any change to the following repair-related requirements: Specifically, a first attempt at repair must be made within 30 days of detecting the fugitive emissions, with final repair, including resurvey to verify repair, completed within 30 days after the first attempt. In addition, owners and operators must develop a fugitive emissions monitoring plan that covers all the applicable requirements for the collection of fugitive emissions components located at a compressor station. In conjunction with the proposed requirement that monitoring be conducted in accordance with the proposed appendix K, we are proposing to require that the monitoring plan also include elements specified in the proposed appendix K when using OGI.

b. EG OOOOc

For existing sources, we are proposing a presumptive standard that includes the same fugitive emissions monitoring and repair program as for new sources. For the reasons discussed in section XII.A.2, the BSER analysis for existing sources supports proposing a presumptive standard for reducing methane emissions from the collection of fugitive emissions components located at existing compressor stations that is the same as what the EPA is proposing for new, modified, or reconstructed sources (for NSPS OOOOb).

Similar to well sites, we are soliciting comment on all aspects of the proposed quarterly monitoring for both new and existing compressor stations, including whether more frequent monitoring would be appropriate. We are also soliciting information on several additional topics. First, the EPA is soliciting comment and data to assess whether compressor stations should be subcategorized for the NSPS and/or the EG, which the EPA could consider through a supplemental proposal. For example, some industry stakeholders have asserted that station throughput directly correlates to the operating pressures, equipment counts, and condensate production, which would influence fugitive emissions at the station. They suggested that subcategorization based on design throughput capacity for the compressor station may be appropriate. We are specifically seeking information related to throughputs where fugitive emissions of methane are demonstrated to be minimal below a certain capacity. While this specific example was raised in the context of existing sources only, the EPA is also soliciting comment on whether new, modified, or reconstructed compressor stations could encounter the same issue and therefore warrant similar subcategorization.

Next, for compressor stations, we are soliciting comment on delayed repairs by existing sources when parts are not readily available and must be special ordered. In comments submitted to the EPA as part of the stakeholder outreach conducted prior to this proposal, industry stakeholders stated that the EPA “should acknowledge that existing sources are older pieces of equipment so there is a higher likelihood that replacement parts will not be readily available; therefore, a lack of available parts should be an appropriate cause to delay a repair.”  ¹⁹⁸ Industry stakeholders further explained that operators will need to special order replacement parts. Further, they stated in their comments that operators should be afforded 30 days to schedule the repair once they have received the replacement part. The EPA is soliciting comment and data to better understand the breadth of this issue with replacement parts for existing compressor stations. Additionally, we are soliciting comment on whether 30 days following receipt of the replacement part is appropriate for completing delayed repairs at existing compressor stations, whether there should be any limit on delays in repairs under these circumstances, and whether this compliance flexibility should be limited or disallowed based on the severity of the leak to be repaired.

¹⁹⁸  Document ID No. EPA-HQ-OAR-2021-0295-0033.

We are also soliciting comment on the specific records that should be maintained and/or reported to justify delayed repairs as a result of part availability issues. Depending on the additional information received, the EPA may consider proposing changes to the proposed EG for compressor stations through a supplemental proposal.

Finally, as discussed in section XI.A.2, the EPA is soliciting comment on whether the scheduling of repairs at compressor stations should be tiered based on severity of the emissions found. Please refer to section XI.A.3 for additional details on this solicitation for comment.

4. Well Sites and Compressor Stations on the Alaska North Slope

For new, reconstructed, and modified well sites and compressor stations located on the Alaska North Slope, based on the rationale provided in section X.B.4.c of this preamble, the EPA is proposing the same monitoring requirements as those in NSPS OOOOa (under newly proposed OOOOb). Also, the EPA is proposing to determine that the same technical infeasibility issues with weather conditions exist for existing well sites and compressor stations located on the Alaska North Slope. Therefore, the EPA is proposing a presumptive standard for reducing methane emissions from the collection of fugitive emissions components located at existing well sites and compressor stations located on the Alaska North Slope (under the newly proposed EG OOOOc) that is the same as what we are proposing for NSPS OOOOb.

Specifically, the EPA is proposing to require annual monitoring of methane and VOC emissions at all well sites and compressor stations located on the Alaska North Slope, with subsequent annual monitoring at least 9 months apart but no more than 13 months apart. The EPA is also proposing to require that new, reconstructed, and modified well sites and compressor stations located on the Alaska North Slope that startup (initially, or after reconstruction or modification) between September and March to conduct initial monitoring of methane and VOC fugitive emissions within 6 months of startup, or by June 30, whichever is later. Finally, the EPA is proposing to require that new, reconstructed, and modified well sites and compressor stations located on the Alaska North Slope that startup (initially, or after reconstruction or modification) between April and August to conduct initial monitoring of methane and VOC fugitive emissions within 90 days of startup.

5. Alternative Screening Using Advanced Measurement Technologies

For new, modified, or reconstructed sources ( i.e., collection of fugitive emissions components located at well sites and compressor stations), the EPA is proposing an alternative fugitive emissions monitoring and repair program that includes bimonthly screening for large emission events using advanced measurement technologies followed with at least annual OGI in accordance with the proposed 40 CFR part 60, appendix K (“appendix K”), which is included in this action and outlines the proposed procedures that must be followed to identify emissions using OGI. ¹⁹⁹ Additionally, we are proposing this same alternative screening using advanced measurement technologies as an alternative presumptive standard for existing sources.

¹⁹⁹  “Determination of Volatile Organic Compound and Greenhouse Gas Leaks Using Optical Gas Imaging” located at Docket ID No. EPA-HQ-OAR-2021-0317.

Specifically, the EPA is proposing to allow owners and operators the option to comply with this alternative fugitive emissions standard instead of the proposed ground based OGI surveys summarized in sections XI.A.2 and XI.A.3. The EPA proposes to require owners and operators choosing this alternative standard to do so for all affected well sites and compressor stations within a company-defined area. This company-defined area could be a county, sub-basin, or other appropriate geographic area. Under this proposed alternative, the EPA proposes to require a screening survey on a bimonthly basis using a methane detection technology that has been demonstrated to achieve a minimum detection threshold of 10 kg/hr. This screening survey would be used to identify individual sites ( i.e., well sites and compressor stations) where a follow-up ground-based OGI survey of all fugitive emissions components at the site is needed because fugitive emissions have been detected. Given the proposed minimum detection threshold of 10 kg/hr, which would constitute a significant emissions event, the EPA believes this follow-up OGI survey should be completed in an expeditious timeframe, therefore we are proposing to require this follow-up OGI survey of all fugitive emissions components at the site within 14 days of the screening survey. However, additional information is needed to fully evaluate the appropriateness of this deadline. Therefore, the EPA is soliciting comment on the proposed 14-day deadline for a follow-up OGI survey and information that would allow further evaluation of other potential deadlines to require.

Next, for sites with emissions identified during screening and subject to this follow-up OGI survey, the EPA proposes that any fugitive emissions identified must be repaired, including those emissions identified during the screening survey. For purposes of this proposal, the EPA is proposing the same repair deadlines as those for the ground based OGI requirements discussed in sections XI.A.2 and XI.A.3, which are a first attempt at repair within 30 days of the OGI survey and final repair completed within 30 days of the first attempt. As noted in section XI.A.1, some equipment types with large emissions warrant a requirement for root cause analysis rather than simply repairing the emission source. The EPA solicits comment on how that root cause analysis with corrective action approach could be applied in this proposed alternative screening approach. Further, because large emission events, especially those identified during the screening surveys, contribute disproportionately to emissions, the EPA is also soliciting comment on how to structure a requirement that would tier repair deadlines based on the severity of the fugitive emissions when using this proposed alternative standard. See section XI.A.2 for additional discussion of this solicitation on tiered repairs.

In addition to the bimonthly screening surveys proposed above, the EPA recognizes that component-level fugitive emissions may still be present at sites where the screening survey does not detect emissions. Therefore, in conjunction with these bimonthly screenings performed with the advanced measurement technology, the EPA is proposing to require a full OGI (or EPA Method 21) survey at least annually at each individual site utilizing the alternative screening standard. If the owner or operator performs an OGI survey in response to emissions found during the bimonthly screening survey, that OGI survey would count as the annual OGI survey; a second survey would not be required to comply with the annual OGI survey requirement and the clock would restart with the next annual survey due within 12 calendar months. The overall purpose of this annual OGI survey is to ensure that each individual site is surveyed with OGI at least annually, even where large emissions are not detected during the screening surveys using advanced measurement technology. The EPA is not allowing EPA Method 21 for use during the proposed follow-up OGI surveys when screening detects emissions because EPA Method 21 is not appropriate for detecting the sources of large emission events, such as malfunctioning control devices.

Finally, the EPA is proposing to require that owners and operators include information specific to the alternative standard within their fugitive emissions monitoring plan. Since the 2016 NSPS OOOOa, owners and operators have been required to develop and maintain a fugitive emissions monitoring plan for all sites subject to the fugitive emissions requirements. This monitoring plan includes information regarding which sites are covered under the plan, which technology is being used ( e.g., OGI or EPA Method 21), and site or company- specific procedures that are employed to ensure compliant surveys. The EPA is proposing to add a requirement that the monitoring plan also address sites that are utilizing the proposed alternative standard. Specifically, the EPA is proposing a requirement to include the following information when the alternative standard is applied:

• Identification of the sites opting to comply with the alternative screening approach;

• General description of each site to be monitored, including latitude and longitude coordinates of the asset in decimal degrees to an accuracy and precision of five decimals of a degree using the North American Datum of 1983;

• Description of the measurement technology;

• Verification that the technology meets the 10 kg/hr methane detection threshold, including supporting data to demonstrate the sensitivity of the measurement technology as applied;

• Procedures for a daily verification check of the measurement sensitivity under field conditions ( e.g., controlled releases);

• Standard operating procedures consistent with EPA's guidance  ²⁰⁰ and to include safety considerations, measurement limitations, personnel qualification/responsibilities, equipment and supplies, data and record management, and quality assurance/quality control ( i.e., initial and ongoing calibration procedures, data quality indicators, and data quality objectives); and

²⁰⁰  Guidance for Preparing Standard Operating Procedures (SOPs), EPA/600/B-07/001, April 2007, https://www.epa.gov/sites/default/files/2015-06/documents/g6-final.pdf .

• Procedures for conducting the screening.

In the event that an owner or operator uses multiple technologies covered by one monitoring plan, the owner or operator would identify which technology is to be used on which site within the monitoring plan.

In addition to the proposed requirements within the monitoring plan, the EPA is also proposing specific recordkeeping and reporting requirements associated with the follow-up OGI surveys that are consistent with the recordkeeping and reporting required for OGI surveys in NSPS OOOOa as amended in the 2020 Technical Rule. See section X.B.1.h and X.B.1.i. The EPA is soliciting comment on when notifications would be required for sites where the alternative standard is applied. Further, the EPA is soliciting comment on whether submission of the monitoring plan, and/or Agency approval before utilizing the alternative standard is necessary to ensure consistency in screening survey procedures in the absence of finalized methods or procedures.

While the EPA is proposing the above alternative screening requirements, additional information is necessary to further refine the specific alternative work practice as it relates to the available technologies. Specific information is requested in the following paragraphs, and, if received, would allow the EPA to better analyze the BSER for fugitive emissions at well sites and compressor stations through a supplemental proposal.

First, the EPA solicits comment on the use of 10 kg/hr as the minimum detection threshold for the advanced measurement technologies used in the alternative screening approach, including data that would support consideration of another detection threshold. The EPA also solicits comment on whether a matrix approach should be developed, instead of prescribing one detection threshold and screening frequency, and what that matrix should look like. In the matrix approach, the frequency of the screening surveys and regular OGI (or EPA Method 21) surveys would be based on the sensitivity of the technology, with the most sensitive detection thresholds having the least frequent screening and survey requirements and the least sensitive detection thresholds having the most frequent screening and survey requirements. For example, sites that are screened using a technology with a detection threshold of 1 kg/hr may require less frequent screening and may require an OGI survey less frequently than sites screened using a technology with a detection threshold of 50 kg/hr. We are also soliciting comment on the detection sensitivity of commercially available methane detection technologies based on conditions expected in the field, as well as factors that affect the detection sensitivity and how the detection sensitivity would change with these factors.

Next, the EPA is soliciting comment on the standard operating procedures being used for commercially available technologies, including any manufacturer recommended data quality indicators and data quality objectives in use to validate these measurements. Additionally, for those commercially available technologies that quantify methane emissions rather than just detect methane, we are soliciting comment on the range of quantification based on conditions one would expect in the field.

The EPA is seeking information that would allow us to further evaluate the potential costs and assumed emission reductions achieved through an alternative screening program. Therefore, the EPA is seeking information on the cost of screening surveys using different types of advanced measurement technologies, singularly or in combination, and factors that affect that cost ( e.g., is it influenced by the number of sites and length of survey). Additionally, we are interested in understanding whether there would be opportunities for cost-sharing among operators and whether any aspect of regulation would be beneficial or required to facilitate such cost-sharing opportunities. We also solicit comment on whether these technologies and cost-sharing opportunities would allow for cost-effective monitoring at all sites owned or operated by the same company within a sub-basin or other discrete geographic area. Further, we seek comment on the current and expected availability of these advanced measurement technologies and the supporting personnel and infrastructure required to deploy them, how their cost and availability might be affected if demand for these technologies were to increase, and how quickly the use of these technologies could expand if they were integrated into this regulatory program either as a required element of fugitive monitoring or as this proposed alternative work practice.

The EPA recognizes that the approach outlined above may not be suited to continuous monitoring technologies, such as network sensors or open-path technology. While these systems typically have the ability to meet the 10 kg/hr methane threshold discussed above  ²⁰¹ the emissions from these well sites can be intermittent or tied to process events ( e.g., pigging operations). We are concerned that the proposed alternative screening approach would trigger an OGI survey for every emission event, regardless of type, duration, or size, if a continuous monitoring technology is installed. This would disincentivize the use of continuous monitoring systems, which could be valuable tools in finding large emission sources sooner. While we believe that a framework for advanced measurement technologies that monitor sites continuously should be developed, we do not currently have all of the information that is necessary to develop an equivalence demonstration for these monitors or to ensure the technology works appropriately over time. Therefore, we are soliciting comment on how an equivalence demonstration can be made for these continuous monitoring technologies.

²⁰¹  Alden et al., Single-Blind Quantification of Natural Gas Leaks from 1 km Distance Using Frequency Combs, Environmental Science and Technology, 2019, 53, 2908-2917.

The framework for a continuous monitoring technology would need to cover the following items at a minimum: The number of monitors needed and the placement of the monitors; minimum response factor to methane; minimum detection level; frequency of data readings; how to interpret the monitor data to determine what emissions are a detection versus baseline emissions; how to determine allowable emissions versus leaks; the meteorological data criteria; measurement systems data quality indicators; calibration requirements and frequency of calibration checks; how downtime should be handled; and how to handle situations where the source of emissions cannot be identified even when the monitor registers a leak. We are soliciting comment on how to develop a framework that is flexible for multiple technologies while still ensuring that emissions are adequately detected and the monitors respond appropriately over time. Additionally, we are soliciting comment on whether these continuous monitors need to respond to other compounds as well as methane; how close a meteorological station must be to the monitored site; and whether OGI or EPA Method 21 surveys should still be required, and if so, at what frequency.

At this time, the EPA does not have enough information to determine how this proposed alternative standard using advanced measurement technologies compares to the proposed BSER of OGI monitoring at well sites at a frequency that is based on the site baseline methane emissions as described in section XI.A.3.a, or to quarterly OGI monitoring at compressor stations. Information provided through this solicitation may be used to reevaluate BSER through a supplemental proposal.

6. Use of Information From Communities and Others

As the EPA learned during the Methane Detection Technology Workshop, industry, researchers, and NGOs have utilized advanced methane detection systems to quickly identify large emission sources and target ground based OGI surveys. State and local governments, industry, researchers, and NGOs have been utilizing advanced technologies to better understand the detection of, source of, and factors that lead to large emission events. The EPA anticipates that the use of these techniques by a variety of parties, including communities located near oil and gas facilities or affected by oil and gas pollution, will continue to grow as these technologies become more widely available and decline in cost.

The EPA is seeking comment on how to take advantage of the opportunities presented by the increasing use of these technologies to help identify and remediate large emission events (commonly known as “super-emitters”). Specifically, the EPA seeks comment on how to evaluate, design, and implement a program whereby communities and others could identify large emission events and, where there is credible information of such a large emission event, provide that information to owners and operators for subsequent investigation and remediation of the event. The EPA understands that these large emission events are often attributable to malfunctions or abnormal process conditions that should not be occurring at a well-operating, well-maintained, and well-controlled facility that has implemented the various BSER measures identified in this proposal.

We generally envision a program for finding large emission events that consists of a requirement that, if emissions are detected above a defined threshold by a community, a Federal or State agency, or any other third party, the owner or operator would be required to investigate the event, do a root cause analysis, and take appropriate action to mitigate the emissions, and maintain records and report on such events.

We seek comment on all aspects of this concept, which would be developed further as part of a supplemental proposal. Among other things, the EPA is soliciting comment on an emissions threshold that could be used to define these large emission events, and which types of technologies would be suitable for identification of large emissions events. For example, there are some satellite systems capable of generally identifying emissions above 100 kg/hr with a spatial resolution which could allow identification of emission events from an individual site. ²⁰² Additionally there are other satellites systems available which have wider spatial resolution that can identify large methane emission events, and when combined with finer resolution platforms, could allow identification of emission events from an individual site. The EPA believes that any emissions visible by satellites should qualify as large emission events. However, the EPA solicits comment on whether the threshold for a large emission should be lower than what is visible by satellite.

²⁰²  D.J. Varon, J. McKeever, D. Jervis, J.D. Maasakkers, S. Pandey, S. Houweling, I. Aben, T. Scarpelli, D.J. Jacob, Satellite Discovery of anomalously Large Methane Point Sources from Oil/Gas Production, available at https://doi.org/10.1029/2019GL083798, October 25, 2019.

Second, in order to make this approach viable, the EPA would need to specify what actions an owner or operator must take when notified of a large emission event, including deadlines for taking such actions. These elements could include the specific steps the company would take to investigate the notification and mitigate the event, such as verifying the location of the emissions, conducting ground investigations to identify the specific emission source, conducting a root cause analysis, performing corrective action within a specific timeframe to mitigate the emissions, and preventing ongoing and future chronic or intermittent large emissions from that source. These steps could be incorporated into a fugitive emissions monitoring plan maintained by the owner or operator, and failure to take the actions specified by the owner or operator in the plan could be considered noncompliance. We seek comment on what specific follow-up actions or other procedures would be appropriate to require once a large emission event is identified, as well as appropriate deadlines for these actions.

Third, the EPA would need to define guidelines for credible and actionable data. The EPA is soliciting comment on what these guidelines should entail and whether specific protocols ( e.g., permissible detection technologies, data analytics, operator training, data reporting, public access, and data preservation) should govern the collection of such data and whether such data should conform to any type of certification. If specific certification or protocols are necessary, the EPA is soliciting comment on how that certification should be obtained.

Fourth, we are also soliciting comment on best practices for the identification of the correct owner or operator of a facility responsible for such large emissions, since such information is necessary to halt such large-volume emission events, and how the community or other third-party should notify the owner or operator, as well as how the delegated authority should be made aware of such notification.

Finally, we are soliciting comment on whether the EPA should develop a model plan for responding to notifications that companies could adopt instead of developing company- or site-specific plans, including what elements should be included in that model plan.

B. Storage Vessels

1. NSPS OOOOb

The current NSPS in subpart OOOOa for storage vessels is to reduce VOC emissions by 95 percent, and the standard applies to a single storage vessel with a potential for 6 or more tpy of VOC emissions. Based on our analysis, which is summarized in section XII.B.1, the EPA is proposing to retain the 95 percent reduction standard as it continues to reflect the BSER for reducing VOC emissions from new storage vessels. The EPA is also proposing to set GHG standards (in the form of limitations on methane emissions) for storage vessels in this action. Because the BSER for reducing VOC and methane emissions are the same, the proposed GHG standard is to reduce methane emissions by 95 percent. The EPA continues to support the capture of gas vapors from storage vessels rather than the combustion of what can be an energy-rich saleable product. We incentivize this by recognizing the use of vapor recovery as a part of the process, therefore the storage vessel emissions would not contribute to the site's potential-to-emit.

Under the current NSPS for storage vessels, an affected facility is a single storage vessel with potential VOC emissions of 6 tpy or greater. The EPA is proposing to include a tank battery as a storage vessel affected facility. The EPA proposes to define a tank battery as a group of storage vessels that are physically adjacent and that receive fluids from the same source ( e.g., well, process unit, compressor station, or set of wells, process units, or compressor stations) or which are manifolded together for liquid or vapor transfer.

To determine whether a single storage vessel is an affected facility, the owner or operator would compare the 6 tpy VOC threshold to the potential emissions from that individual storage vessel; to determine whether a tank battery is an affected facility, the owner or operator would compare the 6 tpy VOC threshold to the aggregate potential emissions from the group of storage vessels. For new, modified, or reconstructed sources, if the potential VOC emissions from a storage vessel or tank battery exceeds the 6 tpy threshold, then it is a storage vessel affected facility and controls would be required. This is consistent with the EPA's initial determination in the 2012 NSPS OOOO that controlling VOC emissions as low as 6 tpy from storage vessels is cost-effective. The proposed standard of 95 percent reduction of methane and VOC emissions, which is the same as the current VOC standard in the 2012 NSPS OOOO and 2016 NSPS OOOOa, can be achieved by capturing and routing the emissions utilizing a cover and closed vent system that routes captured emissions to a control device that achieves an emission reduction of 95 percent, or that routes captured emissions to a process.

Finally, we are proposing specific provisions to clarify what circumstances constitute a modification of an existing storage vessel affected facility (single storage vessel or tank battery), and thus subject it to the proposed NSPS instead of the EG. The EPA is proposing that a single storage vessel or tank battery is modified when physical or operational changes are made to the single storage vessel or tank battery that result in an increase in the potential methane or VOC emissions. Physical or operational changes would be defined to include: (1) The addition of a storage vessel to an existing tank battery; (2) replacement of a storage vessel such that the cumulative storage capacity of the existing tank battery increases; and/or (3) an existing tank battery or single storage vessel that receives additional crude oil, condensate, intermediate hydrocarbons, or produced water throughput (from actions such as refracturing a well or adding a new well that sends these liquids to the tank battery). The EPA is proposing to require that the owner or operator recalculate the potential VOC emissions when any of these actions occur on an existing tank battery to determine if a modification has occurred. The existing tank battery will only become subject to the proposed NSPS if it is modified pursuant to this definition of modification and its potential VOC emissions exceed the proposed 6 tpy VOC emissions threshold.

2. EG OOOOc

Based on our analysis, which is summarized in section XII.B.2, the EPA is proposing EG for existing storage vessels which include a presumptive GHG standard (in the form of limitation on methane emissions). For existing sources under the EG, the EPA is proposing to define a designated facility as an existing tank battery with potential methane emissions of 20 tpy or greater. The proposed definition of a tank battery in the EG is the same as the definition proposed for new sources; however, since the designated pollutant in the context of the EG is methane, determination of whether a tank battery is a designated facility would be based on its potential methane emissions only. Our analysis shows that it is cost effective to control an existing tank battery with potential methane emissions 20 tpy or higher. Similar to the proposed NSPS, we are proposing a presumptive standard that includes a 95 percent reduction of the methane emissions from each existing tank battery that qualifies as a designated facility. Such a standard could be achieved by capturing and routing the emissions by utilizing a cover and closed vent system that routes captured emissions to a control device that achieves an emission reduction of 95 percent, or routes emission back to a process.

C. Pneumatic Controllers

1. NSPS OOOOb

The current NSPS OOOOa regulates certain continuous bleed natural gas driven pneumatic controllers, but includes different standards based on whether the pneumatic controller is located at an onshore natural gas processing plant. If the pneumatic controller is located at an onshore natural gas processing plant, then the current NSPS requires a zero bleed rate. If the pneumatic controller is located elsewhere, then the current NSPS requires the pneumatic controller to operate at a natural gas bleed rate no greater than 6 scfh. The current NSPS does not regulate intermittent vent natural gas driven pneumatic controllers at any location.

Based on our analysis, which is summarized in section XII.C.1, the EPA is proposing pneumatic controller standards for NSPS OOOOb as follows. First, in addition to each single natural gas-driven continuous bleed pneumatic controller being an affected facility, the EPA proposes to define each natural gas-driven intermittent vent pneumatic controller as an affected facility. The EPA believes these pneumatic controllers should be covered by NSPS OOOOb because natural gas-driven intermittent devices represent a large majority of the overall population of pneumatic controllers and are responsible for the majority of emissions from these sources. We are proposing to define an intermittent vent natural gas-driven pneumatic controller as a pneumatic controller that is not designed to have a continuous bleed rate but is instead designed to only release natural gas to the atmosphere as part of the actuation cycle. This affected facility definition would apply at all sites, including natural gas processing plants.

Second, we are proposing a requirement that all controllers (continuous bleed and intermittent vent) must have a VOC and methane emission rate of zero. The proposed rule does not specify how this emission rate of zero must be achieved, but a variety of viable options are discussed in Section XII.C. including the use of pneumatic controllers that are not driven by natural gas such as air-driven pneumatic controllers and electric controllers, as well as natural gas driven controllers that are designed so that there are no emissions, such as self-contained pneumatic controllers. As noted above, the EPA is proposing that the definition of an affected facility would be each pneumatic controller that is driven by natural gas and that emits to the atmosphere. As such, pneumatic controllers that are not driven by natural gas would not be affected facilities, and thus would not be subject to the pneumatic controller requirements of NSPS OOOOb. Similarly, controllers that are driven by natural gas but that do not emit to the atmosphere would also not be affected facilities. In order to demonstrate that a particular pneumatic controller is not an affected facility, owners and operators should maintain documentation to show that such controllers are not natural gas driven such as documentation of the design of the system, and to ensure that they are operated in accordance with the design so that there are no emissions.

In both NSPS OOOO and OOOOa, there is an exemption from the standards in cases where the use of a pneumatic controller affected facility with a bleed rate greater than the applicable standard is required based on functional needs, including but not limited to response time, safety, and positive actuation. The EPA is not maintaining this exemption in the proposed NSPS OOOOb, except for in very limited circumstances explained in section XII.C. As discussed in section XII.C., the reasons to allow for an exemption based on functional need in NSPS OOOO and OOOOa were based on the inability of a low-bleed controller to meet the functional requirements of an owner/operator such that a high-bleed controller would be required in certain instances. Since we are now proposing that pneumatic controllers have a methane and VOC emission rate of zero, we do not believe that the reasons related to the use of low bleed controllers are still applicable. However, EPA is soliciting comment on whether owners/operators believe that maintaining such an exemption based on functional need is appropriate, and if so why.

The proposed rule includes an exemption from the zero-emission requirement for pneumatic controllers in Alaska at locations where power is not available. In these situations, the proposed standards require the use of a low-bleed controller instead of high-bleed controller. Further, in these situations (controllers in Alaska at location without power) the proposed rule includes the exemption that would allow the use of high-bleed controllers instead of low-bleed based on functional needs. Lastly, in these situations owners/operators must inspect intermittent vent controllers to ensure they are not venting during idle periods.

2. EG OOOOc

In this action, the EPA is proposing to define designated facilities (existing sources) analogous to the affected facility definitions described above for pneumatic controllers under the NSPS. For the reasons discussed in section XII.C.2, the BSER analysis for existing sources supports proposing presumptive standards for reducing methane emissions from existing pneumatic controllers that are the same as those the EPA is proposing for new, modified, or reconstructed sources (for NSPS OOOOb).

D. Well Liquids Unloading Operations

Well liquids unloading operations, which are currently unregulated under the NSPS OOOOa, refer to unloading of liquids that have accumulated over time in gas wells and are impeding or halting production. The EPA is proposing standards in the NSPS OOOOb to reduce methane and VOC emissions during liquids unloading operations.

1. NSPS OOOOb

We are proposing standards to reduce VOC and methane emissions from each well that conducts a liquids unloading operation. Based on our analysis, which is summarized in section XII.D.1, we are proposing a standard under NSPS OOOOb that requires owners or operators to perform liquids unloading with zero methane or VOC emissions. In the event that it is technically infeasible or not safe to perform liquids unloading with zero emissions, the EPA is proposing to require that an owner or operator establish and follow BMPs to minimize methane and VOC emissions during liquids unloading events to the extent possible.

The EPA is co-proposing two regulatory approach options to implement the rule requirements.

For Option 1, the affected facility would be defined as every well that undergoes liquids unloading. This would mean that wells that utilize a non-emitting method for liquids unloading would be affected facilities and subject to certain reporting and recordkeeping requirements. These requirements would include records of the number of unloadings that occur and the method used. A summary of this information would also be required to be reported in the annual report. The EPA also recognizes 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 Option 1 owners and operators in this situation would be 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 maximum extent possible.

For wells that utilize methods that vent to the atmosphere, the proposed rule would require that owners or operators (1) Document why it is infeasible to utilize a non-emitting method due to technical, safety, or economic reasons; (2) develop BMPs that ensure that emissions during liquids unloading are minimized including, at a minimum, having a person on-site during the liquids unloading event to expeditiously end the venting when the liquids have been removed; (3) follow the BMPs during each liquids unloading event and maintain records demonstrating they were followed; and (4) report the number of liquids unloading events in an annual report, as well as the unloading events when the BMP was not followed. While the proposed rule would not dictate all of the specific practices that must be included, it would specify minimum acceptance criteria required for the types and nature of the practices. Examples of the types and nature of the required practice elements are provided in XII.D.1.e.

For Option 2, the affected facility would be defined as every well that undergoes liquids unloading using a method that is not designed to totally eliminate venting. The significant difference in this option is that wells that utilize non-venting methods would not be affected facilities that are subject to the NSPS OOOOb. Therefore, they would not have requirements other than to maintain records to document that they used non-venting liquids unloading methods. The requirements for wells that use methods that vent would be the same as described above under Option 1. The EPA solicits comment on including information such as where the well stream was directed during unloading and emissions manifested and whether an estimate of the VOC and methane emissions generated should be included in the annual report.

There are several techniques owners and operators can choose from to unload liquids, including manual unloading, velocity tubing or velocity strings, beam or rod pumps, electric submergence pumps, intermittent unloading, gas lift ( e.g., use of a plunger lift), foam agents, wellhead compression, and routing the gas to a sales line or back to a process. Although the unloading method employed by an owner or operator can itself be a method that can be employed in such a way that mitigates/eliminates venting of emissions from a liquids unloading event, indicating a particular method to meet a particular well's unloading needs is a production engineering decision. Based on available information, liquids unloading operations are often conducted in such a way that eliminates venting to the atmosphere and there are many options that include techniques and procedures that an owner or operator can choose from to achieve this standard (discussed in section XII.D.e of this preamble).

However, the EPA recognizes that there may be reasons that a non-venting method is infeasible for a particular well, and the proposed rule would allow for the use of BMPs to reduce the emissions to the maximum extent possible for such cases (discussed in section XII.D of this preamble). BMPs include, but are not limited to, following specific steps that create a differential pressure to minimize the need to vent a well to unload liquids and reducing wellbore pressure as much as possible prior to opening to atmosphere via storage tank, unloading through the separator where feasible, and requiring an operator to remain on-site throughout the unloading, and closure of all well head vents to the atmosphere and return of the well to production as soon as practicable. For example, where a plunger lift is used, the plunger lift can be operated so that the plunger returns to the top and the liquids and gas flow to the separator. Under this scenario, venting of the gas can be minimized and the gas that flows through the separator can be routed to sales. In situations where production engineers select an unloading technique that vents emissions or has the potential to vent emissions to the atmosphere, owners and operators already often implement BMPs in order to increase gas sales and reduce emissions and waste during these (often manual) liquids unloading activities.

2. EG OOOOc

The EPA has determined that each well liquids unloading event represents a modification, which will make the well subject to new source standards under the NSPS for purposes of the liquids unloading standards. ²⁰³ Therefore, after the effective date of NSPS OOOOb, the first time a well undergoes liquids unloading it will become subject to NSPS OOOOb. This will mean that there will never be a well that undergoes liquids unloading that will be existing. Therefore, we are not proposing presumptive standards under the subpart OOOOc EG.

²⁰³  To clarify further, when a well liquids unloading event represents a modification, this does not make the whole well site a new source. Rather, the modification will make the well subject to NSPS for only the liquids unloading standards.

E. Reciprocating Compressors

1. NSPS OOOOb

The current NSPS in subpart OOOOa for reducing VOC and methane emissions from reciprocating compressors is to replace the rod packing on or before 26,000 hours of operation or 36 calendar months, or to route emissions from the rod packing to a process through a closed vent system under negative pressure. The affected facility is each reciprocating compressor, with the exception of reciprocating compressors located at well sites. Based on the analysis in section XII.E.1, the proposed BSER for reducing GHGs and VOC from new reciprocating compressors is replacement of the rod packing based on an annual monitoring threshold. Under this proposal for the NSPS, we would continue to retain, as an alternative, the option of routing rod packing emissions to a process via a closed vent system under negative pressure. In this proposed updated standard, the owner or operator of a reciprocating compressor affected facility would be required to monitor the rod packing emissions annually using a flow measurement. When the measured leak rate exceeds 2 scfm (in pressurized mode), replacement of the rod packing would be required.

As mentioned above, reciprocating compressors that are located at well sites are not affected facilities under the 2016 NSPS OOOOa. The EPA previously excluded them because we found the cost of control to be unreasonable. 81 FR 35878 (June 3, 2016). Our current analysis, as summarized in section XII.E.1, continues to support this exclusion for a subset of well sites so this proposal for NSPS OOOOb includes that same exclusion for well sites that are not centralized production facilities. See section XI.L for additional details on centralized production facilities. As described in that section, the EPA is proposing to apply the proposed standards to reciprocating compressors located at centralized production facilities.

2. EG OOOOc

Based on the analysis in section XII.E.2, the EPA is proposing EG that include a presumptive GHG standard (in the form of limitation on methane emissions) for existing reciprocating compressors that is the same as the proposed NSPS, including applying these presumptive standards to reciprocating compressors located at existing centralized tank batteries.

F. Centrifugal Compressors

1. NSPS OOOOb

The current NSPS in subpart OOOOa for wet seal centrifugal compressors is 95 percent reduction of GHGs and VOC emissions. The affected facility is each wet seal centrifugal compressor, with the exception of wet seal centrifugal compressors located at well sites. Based on the analysis in section XII.F.1, the BSER for reducing GHGs and VOC from new, reconstructed, or modified wet seal centrifugal compressors is the same as the current standard, which is 95 percent reduction of GHG and VOC emissions. The standard can be achieved by capturing and routing the emissions, using a cover and closed vent system, to a control device that achieves an emission reduction of 95 percent, or by routing captured emissions to a process.

As discussed above, wet seal centrifugal compressors that are located at well sites are not affected facilities under the 2016 NSPS OOOOa. The EPA previously excluded them because data available at the time did not suggest there were a large number of wet seal centrifugal compressors located at well sites. 81 FR 35878 (June 3, 2016). Our analysis continues to support this exemption for wet seal centrifugal compressors located at well sites that are not centralized production facilities. See section XI.L for additional details on centralized production facilities. As described in that section, the EPA is proposing to apply the proposed standards to centrifugal compressors located at centralized production facilities.

2. EG OOOOc

Based on the analysis in section XII.F.2, the EPA is proposing EG that include a presumptive GHG standard (in the form of limitation on methane emissions) for existing wet seal centrifugal compressors that is the same as the NSPS, including applying these presumptive standards to wet seal centrifugal compressors at existing centralized tank batteries.

G. Pneumatic Pumps

1. NSPS OOOOb

The current NSPS in subpart OOOOa regulates individual natural gas driven diaphragm pneumatic pumps at well sites and at onshore natural gas processing plants. The current NSPS for a natural gas driven diaphragm pneumatic pump at well sites requires 95 percent control of GHGs and VOCs if there is an existing control device or process on site where emissions can be routed. There are two exceptions to the 95 percent control requirement: (1) The existing control or process achieves less than 95 percent reduction; or (2) it is technically infeasible to route to the existing control device or process. In addition, the current NSPS in OOOOa specifies that boilers and process heaters are not considered control devices and that routing emissions from pneumatic pump discharges to boilers and process heaters is not considered routing to a process. For more discussion on the use of boilers and process heaters as control devices for pneumatic pump emissions, see section X.B.2 of this preamble. The current NSPS for a natural gas driven diaphragm pneumatic pump at an onshore natural gas processing plant is a natural gas emission rate of zero, based on natural gas as a surrogate for VOC and GHG, the two regulated pollutants.

For NSPS OOOOb, we are proposing to expand the applicability of the standard currently in NSPS OOOOa in two ways. The first is by including all natural gas driven diaphragm pumps as affected facilities in the transmission and storage segment in addition to the production and natural gas processing segments. The second is that we are expanding the affected facility definition to include natural gas driven piston pumps in addition to diaphragm pumps. The proposed definition of an affected facility would continue to exclude lean glycol circulation pumps that rely on energy exchange with the rich glycol from the contractor.

Based on our analysis, which is summarized in section XII.G.1, we are proposing to retain the current standard for a natural gas driven diaphragm pneumatic pump at well sites because the BSER for reducing VOC and methane emissions from such pumps at a well site continues to be routing to a combustion device or process, but only if the control device or process is already available on site. As before, the current analysis continues to show that it is not cost-effective to require the owner or operator of a pneumatic pump to install a new control device or process onsite to capture emissions solely for this purpose. Moreover, even where a control device or process is available onsite that would achieve at least 95 percent control, the EPA is aware that it may not be technically feasible in some instances to route the pneumatic pump to the control device or process. In this situation, the proposed rule would exempt the owner and operator from this requirement provided that they document the technical infeasibility and submit it in an annual report. Another circumstance is that it may be feasible to route the emissions to a control device, but the control cannot achieve 95 percent control. In this instance, the proposed rule would exempt the owner or operator from the 95 percent requirement, provided that the owner or operator maintain records demonstrating the percentage reduction that the control device is designed to achieve. In this way, the standard would achieve emission reductions with regard to pneumatic pump affected facilities even if the only available control device cannot achieve a 95 percent reduction. For more discussion of the technical infeasibility aspects of the pneumatic pump requirements, see section X.B.2 of this preamble. We are proposing to expand these requirements to all diaphragm pumps at all sites in the production segment, as well as at all transmission and storage sites. In addition, we are proposing that these requirements would also include emissions from piston pneumatic pumps at all sites in the production segment.

We are not proposing any change to the current standard of zero natural gas emission for natural gas driven diaphragm pneumatic pumps located at onshore natural gas processing plants, other than the expansion of the affected facility definition to include piston pumps. Our analysis discussed in section XII.G.1 demonstrates this standard is the BSER.

2. EG OOOOc

The EPA is proposing EG that include presumptive methane standards that are the same as described above for the NSPS OOOOb for existing natural gas driven diaphragm pneumatic pumps located at well sites and all other sites in the production segment (except processing plants) and transmission and storage segment where an existing control device exists. However, unlike the proposed methane standards in NSPS OOOOb for natural gas driven piston pneumatic pumps at sites in the production segment, the proposed presumptive standards under EG OOOOc exclude piston pumps from the 95 percent control requirements. The EPA's proposed emissions guidelines also include a presumptive methane standard for pneumatic pumps located at onshore natural gas processing plants that is the same as the proposed NSPS described above.

H. Equipment Leaks at Natural Gas Processing Plants

Based on our analysis, which is summarized in section XII.H.1, the EPA is proposing to update the NSPS for reducing VOC and methane emissions from equipment leaks at onshore natural gas processing plants. Further, based on the same analysis in section XII.H.1 and the EPA's understanding that it is appropriate to apply that same analysis to existing sources, the EPA is also proposing EG that include these same LDAR requirements as presumptive standards for reducing methane leaks from existing equipment at onshore natural gas processing plants.

The EPA is proposing to expand the definition of an affected facility (referred to as a “equipment within a process unit”) and establish a new standard for reducing equipment leaks of VOC and methane emissions from new, modified, and reconstructed process units at onshore natural gas processing plants. This proposed standard would require (1) the use of OGI monitoring to detect equipment leaks from pumps, valves, and connectors, and (2) retain the current requirements in the 2016 NSPS OOOOa (which adopts by reference specific provisions of 40 CFR part 60, subpart VVa (“NSPS VVa”)) for PRDs, open-ended valves or lines, and closed vent systems and equipment designated with no detectable emissions.

First, we are proposing to remove a threshold that excludes certain equipment within a process unit from being subject to the equipment leaks standards for onshore natural gas processing plants. While the current definition of an affected facility includes all equipment, except compressors, that is in contact with a process fluid containing methane or VOCs ( i.e., each pump, PRD, open-ended valve or line, valve, and flange or other connector), the standards apply only to equipment “in VOC service,” which “means the piece of equipment contains or contacts a process fluid that is at least 10 percent VOC by weight.” We are proposing to remove this VOC concentration threshold from the LDAR requirements for the following reasons. First, a VOC concentration threshold bears no relationship to the LDAR for methane and is therefore not an appropriate threshold for determining whether LDAR for methane applies. Second, since there would be no threshold for requiring LDAR for methane, any equipment not in VOC service would still be required to conduct LDAR for methane even if not for VOC, thus rendering this VOC concentration threshold irrelevant.

Second, for all pumps, valves, and connectors located within an affected process unit at an onshore natural gas processing plant, we are proposing to require the use of OGI to identify leaks from this equipment on a bimonthly frequency ( i.e., once every other month), which according to our analysis is the BSER for identifying and reducing leaks from this equipment. OGI monitoring would be conducted in accordance with the proposed appendix K, ²⁰⁴ which is included in this action and outlines the proposed procedures that must be followed to identify leaks using OGI. As an alternative to bimonthly monitoring using OGI, we are proposing to allow affected facilities the option to comply with the requirements of NSPS VVa, which are the current requirements in the 2016 NSPS OOOOa. ²⁰⁵ As explained in XII.A, our analysis shows that the proposed standards, which use OGI, achieve equivalent reduction of VOC and methane emissions as the current standards, which are based on EPA Method 21, but at a lower cost. While we no longer consider EPA Method 21 to be the BSER for reducing methane and VOC emissions from equipment leaks at onshore natural gas processing plants, we are retaining NSPS VVa as an alternative for owners and operators who prefer using EPA Method 21.

²⁰⁴  “Determination of Volatile Organic Compound and Greenhouse Gas Leaks Using Optical Gas Imaging” located at Docket ID No. EPA-HQ-OAR-2021-0317.

²⁰⁵  It is important to note that the stay of the connector monitoring requirements in 40 CFR 60.482-11a does not apply to connectors located at onshore natural gas processing plants. Therefore, where sources choose to comply with the requirements of NSPS VVa in place of the proposed OGI requirements, the standards in 40 CFR 60.482-11a are applicable to all connectors in the process unit.

Third, we are proposing to require a first attempt at repair for all leaks identified with OGI within 5 days of detection, and final repair completed within 15 days of detection. We are also proposing definitions for “first attempt at repair” and “repaired.” The proposed definitions would apply to the equipment leaks standards at natural gas processing plants as well as to fugitive emissions requirements at wel