Document ID: EPA-HQ-OAR-2021-0317-0140
Agency: epa
Document Type: Supporting & Related Material
Title: 
Posted Date: 2021-11-15T05:00Z

EO12866_Oil and Gas NSPS EG Climate Review 2060-AV15 and 2060-AV16 PROPOSAL 20210910
                                                                      6560-50-P
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 60	
[EPA-HQ-OAR-2021-0317; FRL-XXXXX-XX-OAR] 
RIN 2060-AV15 and 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 proposed rule comprises three distinct actions under section 111 of 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 section 111(b) to reflect the Agency's most recent review of the feasibility and cost of reducing emissions from these sources. Second, this action proposes emissions guidelines (EG) under CAA section 111(d), 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, this action proposes to implement regulatory changes resulting from the June 30, 2021, joint resolution of disapproval of the final rule titled "Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources Review," 85 FR 57018 (September 14, 2020), enacted pursuant to the Congressional Review Act (CRA), and to address conflicting VOC standards and other modifications 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). This proposal responds to the President's Executive Order (EO) 13990, "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 (January 20, 2021).
DATES: Comments. Comments must be received on or before [INSERT DATE 60 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]. 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 [INSERT DATE 30 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER].
	Public hearing: The EPA will hold a virtual public hearing on [INSERT DATE 15 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER] and [INSERT DATE 16 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]. 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 [INSERT DATE 15 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER], and [INSERT DATE 16 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER], 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 [INSERT DATE 17 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]. 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 [INSERT DATE 9 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]. 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 [INSERT DATE 7 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]. 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
CH4	methane
cm	centimeter
CPI	consumer price index
CPI-U	consumer price index urban
CO	carbon monoxide
COPD	chronic obstructive pulmonary desease
CO2	carbon dioxide
CO2 Eq.	carbon dioxide equivalent
COA	condition of approval
COS	carbonyl sulfide
CRA	Congressional Review Act
CS2	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
H2S	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
NOx	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	hazardous materials safety administration 
PM	particulate matter
PM2.5		         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-CH4	social cost of methane
SCF	significant contribution finding
scf	standard cubic feet
scfh	standard cubic feet per hour
scfm 	standard cubic feet per minute
SF6	sulfur hexafluoride
SIP	state implementation plan
SO2	sulfur dioxide
SOx	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. Crude Oil and Natural Gas Emissions and Climate Change
A. Impacts of GHGs, VOC and SO2 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 this information is being considered in this proposal?
 VIII. Legal Basis for Proposal 
 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 OOOO and 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. Sweetening Units  
 K. Centralized Production Facilities
 L. Recordkeeping and Reporting 
 M. 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 Sweetening Units  
 K. Proposed Standards for Recordkeeping and Reporting 
 XIII. Solicitations for Comment on Additional Emission Sources and Definitions
A. Associated Gas
B. Abandoned Wells
C. Pigging Operations and Related Blowdown Activities
D. Tank Truck Loading
E. Control Device Efficiency and Operation
F. 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 change and improving human health by reducing GHG and VOC emissions from the Oil and Natural Gas Industry, specifically the Crude Oil and Natural Gas source category. The Oil and Natural Gas Industry is the United States' largest industrial emitter of methane. 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 Intergovernmental Panel on Climate Change (IPCC), strong, rapid, and sustained methane reductions are critical to reducing near-term disruption of the climate system and a vital complement to carbon dioxide (CO2) reductions critical in limiting the long-term extent of climate change and its destructive impacts. The Oil and Natural Gas Industry also emits other health-harming pollutants in varying concentrations and amounts, including CO2, VOC, sulfur dioxide (SO2), nitrogen oxide (NOx), hydrogen sulfide (H2S), carbon disulfide (CS2), and carbonyl sulfide (COS), as well as, benzene, toluene, ethylbenzene and xylenes (this group is commonly referred to as ``BTEX''), and n-hexane.
      Under the authority of CAA section 111, this rulemaking 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 (existing sources), 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. 
      The EPA is proposing these actions in accordance with its legal obligations and authorities following a review directed by EO 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, "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." 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 America, 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 CO2, and also contributes to the creation of ground-level ozone which is another greenhouse gas. Methane has a global warming potential (GWP) of almost 30 which means that the emissions of one ton of methane has approximately as much climate impact over a 100-year period as the emissions of almost 30 tons of carbon dioxide. 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 CO2 emissions", though they also 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 CO2." 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) in 2040 and 0.8°C by the end of the century, which is important in the context of keeping warming to well below 2°C. As methane is the most important SLCF, this makes methane mitigation one of the best opportunities for reducing near term warming. Human emissions have already more than doubled atmospheric methane concentrations since 1750, and that concentration has been growing larger at record rates in recent years. In the absence of additional reduction policies, methane emissions are projected to continue rising through at least 2040. 
      Methane's radiative efficiency means that reductions now in methane emissions can help reduce near-term warming. As natural gas is comprised primarily of methane, every natural gas leak or intentional release through venting or other process 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 SO2 Emissions on Public Health and Welfare.
      Methane and VOC emissions from the Crude Oil and Natural Gas source category are the result of industry operations, such as venting or under-performing flaring of associated gas from oil wells, oil storage vessels, and production-related equipment such as natural gas dehydrators, pig launchers and receivers, and pneumatic devices. As natural gas moves through the interconnected system, emissions primarily result from intentional venting, unintentional gas carry through, routine maintenance, unintentional fugitive emissions, flaring, malfunctions, abnormal process conditions, and system upsets. 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 most attainable 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,
 limit 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 in a potential supplemental rulemaking proposal under both CAA section 111(b) and (d).
      In developing this proposal, the EPA applied lessons learned from states' regulatory efforts; reviewed information about new and developing technologies, reviewed peer-reviewed research of emission measurement campaigns across the United States (U.S.); built upon emission reduction efforts of leading companies; considered communities' concerns, especially those with environmental justice implications; and used information and ideas collected through the EPA's extensive pre-proposal outreach. 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 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 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 with the public, including 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 ways to allow use of cutting-edge technologies for detecting methane and VOC emissions, including credible surveys undertaken by communities and other third parties. The sets of measures in this proposal, if finalized, would help reduce health impacts on communities adjacent to these emission sources. 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.
      The EPA believes that an "all-hands-on-deck" effort across all states and all federal agencies is essential to meaningfully address climate change. As the federal agency with primary responsibility to protect human health and the environment, the EPA has the unique responsibility and authority to regulate harmful air pollutants emitted by the Crude Oil and Natural Gas source category. The EPA recognizes that states and other federal agencies regulate in accordance with their respective legal authorities and within their respective jurisdictions, and 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 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 either are unregulated or from which additional, cost-effective reductions are available. The EPA is committed to acting within its authority to provide opportunities for aligning its programs with other existing state and Federal programs in order to reduce unnecessary regulatory redundancy where appropriate, and the EPA will continue dialogue with its federal partners to minimize potential regulatory conflicts and regulatory burden on the part of owners and operators. 
      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 achieves the greatest possible reductions in methane and VOC emissions while being achievable and cost effective. In light of certain innovative elements of this proposed rulemaking and the potential of including additional sources as affected facilities for regulation, the EPA is considering issuing a supplemental proposed rule to allow the Agency to refine or expand this proposed rulemaking as appropriate in response to comments and information received in response.
B. Summary of the Major Provisions of this Regulatory Action 
      This proposed rulemaking includes three distinct actions under the CAA that are each severable from the other. First, pursuant to CAA 111(b)(1)(B), has reviewed, and is proposing revisions of, 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 [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER]. These proposed standards of performance will be in a new subpart, 40 CFR part 60, subpart OOOOb (NSPS OOOOb), and also 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, this rulemaking proposes to implement regulatory changes resulting from the June 30, 2021, joint resolution of disapproval of the final rule titled "Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources Review," 85 FR 57018 (September 14, 2020) (2020 Policy Rule), enacted pursuant to the CRA, and to address (1) certain resulting inconsistencies between the VOC and methane standards resulting from the CRA, and (2) revisiting 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), particularly with respect to fugitive emissions monitoring at low production well sites and gathering and boosting stations. As described below, the EPA also proposed 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. For this third element of the proposal, the EPA is proposing amendments to its 2012 NSPS titled "Subpart OOOO-Standards of Performance For Crude Oil and Natural Gas Facilities for which Construction, Modification, or Reconstruction Commenced After August 23, 2011, and on or Before September 18, 2015" (2012 NSPS OOOO) and to its 2016 NSPS OOOOa (as amended by 2020 Technical Rule).   
      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 and the achievable emission reductions 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, in order to appropriately take into account that the systems of emission reduction considered in this rule typically achieve reductions in multiple pollutants at once and secure a multiplicity of climate and public health benefits. For a detailed discussion of the EPA's consideration of this and other BSER statutory elements, please see sections IV and IX of this preamble.  
TABLE 1: APPLICABILITY DATES FOR PROPOSED SUBPARTS ADDRESSED IN THIS PROPOSED ACTION
                                    Subpart
                                  Source Type
                               Applicable Dates
40 CFR part 60, subpart OOOOa 
New, modified, or reconstructed sources
After September 18, 2015 and on or before [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER]
40 CFR part 60, subpart OOOOb
New, modified, or reconstructed sources
After [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER]
40 CFR part 60, subpart OOOOc
Existing sources
On or before [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER]
                                       
1. Proposed Standards for New, Modified and Reconstructed Sources after [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER] (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 SO2 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 [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER], which is the date of publication of the proposed revisions to the NSPS. In particular, this action proposes to retain the 2016 NSPS OOOOa SO2 performance standard for sweetening units and the 2016 OOOOa VOC and methane performance standard for well completions; 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, centrifugal 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 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 flaring and venting of associated gas, 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 ([INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER] (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, unless a state chooses 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, assuming that 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, 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. 
      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 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 flaring and venting at wells producing associated gas, 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.
3. Proposed Amendments to 2012 NSPS OOOO and 2016 NSPS OOOOa
      In this rulemaking, the EPA also is proposing amendments to its 2012 NSPS OOOO and 2016 NSPS OOOOa, in order to address the June 30, 2021, joint resolution under the CRA that disapproved the 2020 Policy Rule. By the terms of the CRA, the signing into law of the 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). Thus, the EPA is proposing to amend the regulatory text for the 2012 NSPS OOOO rule to reflect requirements for VOC emissions from sources in the transmission and storage segment that the 2020 Policy Rule had rescinded, and that the resolution of disapproval reinstated. See section VIII and section X of this preamble for further discussion on the Legal Basis for Proposal and the Summary of Proposed Action for NSPS OOOO and NSPS OOOOa.
      The EPA is further proposing to amend the regulatory text for the 2016 NSPS OOOOa to reflect requirements for methane emissions from sources in the production, processing, and transmission and storage segments that the 2020 Policy Rule had rescinded and that the resolution of disapproval reinstated. The EPA is also proposing certain additional 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 segments 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.
 TABLE 2: SUMMARY OF PROPOSED BSER AND PROPOSED STANDARDS OF PERFORMANCE FOR GHGS AND VOC (NSPS OOOOb)
 Affected Source
 Proposed BSER
 Proposed Standards of Performance for GHGs and VOCs
 Fugitive Emissions: Well Sites with Baseline Emissions >=15 tpy[1] Methane
 Monitoring and repair based on quarterly monitoring using OGI[2]. 
 
 
Quarterly OGI monitoring following Appendix K. (Optional quarterly EPA Method 21 monitoring with 500 ppm[3] defined as a leak).
 First attempt at repair within 30 days of finding fugitive emissions. Final repair within 30 days of first attempt.
 Fugitive Emissions: Well Sites with Baseline Emissions >=5 to <15 tpy Methane
 Monitoring and repair based on semiannual monitoring using OGI. 
 
 
Semiannual OGI monitoring following Appendix K. (Optional semiannual EPA Method 21 monitoring with 500 ppm defined as a leak).

 First attempt at repair within 30 days of finding fugitive emissions. Final repair within 30 days of first attempt.
 Fugitive Emissions: Well Sites with Baseline Emissions >0 to <5 tpy Methane
 Calculate and maintain record of baseline methane emissions.
Calculate and maintain record of baseline methane emissions.
 Fugitive Emissions: Compressor Stations
 Monitoring and repair based on quarterly monitoring using OGI. 
 
 
Quarterly OGI monitoring following Appendix K. (Optional quarterly EPA Method 21 monitoring with 500 ppm defined as a leak).

First attempt at repair within 30 days of finding fugitive emissions. Final repair within 30 days of first attempt.
 Storage Vessels: Tank Battery with PTE[4] of 6 tpy or More of VOC
 Capture and route to a control device. 
95 percent reduction.
 Pneumatic Controllers: Subcategory 1 (at sites with onsite power available)
 Non-emitting pneumatic controllers.
VOC and methane emission bleed rate of zero.
 Pneumatic Controllers: Subcategory 2 (at sites where onsite power is not available -continuous bleed natural gas driven)
 Installation of low-bleed pneumatic controllers.
Natural gas bleed rate no greater than 6 scfh[5].
 Pneumatic Controllers: Subcategory 2 (at sites where onsite power is not available -intermittent natural gas driven)
 Monitor and repair through fugitive emissions program.
OGI monitoring and repair of emissions from controller malfunctions.
 Pneumatic Controllers: Natural Gas Processing Plants. 
 Instrument air systems.
Zero natural gas bleed rate.
 Well Liquids Unloading
 Perform liquids unloading with zero methane or VOC emissions. If this is not feasible for safety or technical reasons, employ best management practices to minimize venting. 
Each affected well that unloads liquids employ techniques or technology(ies) that eliminate or minimize venting of emissions during liquids unloading events to the maximum extent. 
 
Co Proposal Options: 
 
Option One- Affected facility would be defined as every well that undergoes liquids unloading. 
-If the method is one that does not result in any venting to the atmosphere, maintain records specifying the technology or technique and record instances where an unloading event results in emissions. 
-For unloading technologies or techniques that result in venting to the atmosphere, implement BMPs[6] to ensure that venting is minimized. 
-Maintain BMPs as records, and record instances when they were not followed. 
 
Option Two - Affected facility would be defined as every well that undergoes liquids unloading using a method that is not designed to totally eliminate venting. 
 - -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 demonstrate that they did not use non-venting methods and were not subject to NSPS OOOOb.  
-The requirements for wells that use methods that vent would be the same as described above under Option 1.
 Wet Seal Centrifugal Compressors (except for those located at single well sites).
 Capture and route to a control device. 
95 percent reduction.
 Reciprocating Compressors (except for those located at single well sites). 
 Rod packing changeout based on annual monitoring (when measured leak rate exceeds 2 scfm[7]). 
Replace the rod packing when measured leak rate exceeds 2 scfm based on the results of annual monitoring or route emissions from the rod packing to a process through a closed vent system under negative pressure.
 Pneumatic Pumps: Natural Gas Processing Plants.
 Instrument air systems in place of natural gas driven pumps.
Zero natural gas emissions.
 Pneumatic Pumps: Locations Other Than Natural Gas Processing Plants.
 Route to existing control device or process. 
95 percent control if there is an existing control or process on site. 95 percent control not required if 
(1) routed to an existing control that achieves less than 95 percent or (2) it is technically infeasible to route to the existing control device or process.
 Well Completions: Subcategory 1 (non-wildcat and non-delineation wells).
 Combination of REC[8] and the use of a completion combustion device.
REC in combination with a completion combustion device; venting in lieu of combustion where combustion would present safety hazards.  

Initial flowback stage: Route to a storage vessel or completion vessel (frac tank, lined pit, or other vessel) and separator.

Separation flowback stage: Route all salable gas from the separator to a flow line or collection system, re-inject the gas into the well or another well, use the gas as an onsite fuel source or use for another useful purpose that a purchased fuel or raw material would serve. If technically infeasible to route recovered gas as specified above, recovered gas must be combusted. All liquids must be routed to a storage vessel or well completion vessel, collection system, or be re-injected into the well or another well.

The operator is required to have (and use) a separator onsite during the entire flowback period.
 Well Completions: Subcategory 2 (exploratory and delineation wells and low-pressure wells).
 Use of a completion combustion device.
The operator is not required to have a separator onsite. Either: (1) Route all flowback to a completion combustion device with a continuous pilot flame; or (2) Route all flowback into one or more well completion vessels and commence operation of a separator unless it is technically infeasible for a separator to function. Any gas present in
the flowback before the separator can function is not subject to control under this section. Capture and direct recovered gas to a completion combustion device with a continuous pilot flame. 

For both options (1) and (2), combustion is not required in conditions that may result in a fire hazard or explosion, or where high heat emissions from a completion combustion device may negatively impact tundra, permafrost or waterways. 
 Equipment Leaks at Natural Gas Processing Plants.
 LDAR[9] with bimonthly OGI.
 LDAR with OGI following procedures in Appendix K. 
 Sweetening Units.
 Achieve SO2 emission reduction efficiency.
 Achieve required minimum SO2 emission reduction efficiency.
[1] tpy (tons per year)
[2] OGI (optical gas imaging)
[3] ppm (parts per million)
[4] PTE (potential to emit)
[5] scfh (standard cubic feet per hour)
[6] BMP (best management practices)
[7] scfm (standard cubic feet per minute)
[8] REC (reduced emissions completion)
9 LDAR (leak detection and repair)

 TABLE 3: SUMMARY OF PROPOSED BSER AND PROPOSED PRESUMPTIVE STANDARDS FOR GHGS FROM DESIGNATED FACILITIES (EG OOOOc)
 Designated Facility
 Proposed BSER
 Proposed Presumptive Standards for GHGs 
 Fugitive Emissions: Well Sites >=15 tpy Methane
 Monitoring and repair based on quarterly monitoring using OGI. 
 
 
Quarterly OGI monitoring following Appendix K. (Optional quarterly EPA Method 21 monitoring with 500 ppm defined as a leak).

 First attempt at repair within 30 days of finding fugitive emissions. Final repair within 30 days of first attempt.
 Fugitive Emissions: Well Sites >=5 to <15 tpy Methane
 Monitoring and repair based on semiannual monitoring using OGI. 
 
 
Semiannual OGI monitoring following Appendix K. (Optional semiannual EPA Method 21 monitoring with 500 ppm defined as a leak).

 First attempt at repair within 30 days of finding fugitive emissions. Final repair within 30 days of first attempt.
 Fugitive Emissions: Well Sites >0 to <5 tpy Methane
 Calculate and maintain record of baseline methane emissions.
Calculate and maintain record of baseline methane emissions.
 Fugitive Emissions: Compressor Stations
 Monitoring and repair based on quarterly monitoring using OGI. 
 
 
Quarterly OGI monitoring following Appendix K. (Optional quarterly EPA Method 21 monitoring with 500 ppm defined as a leak).

First attempt at repair within 30 days of finding fugitive emissions. Final repair within 30 days of first attempt.
 Storage Vessels: Tank Battery with PTE of 20 tpy or More of Methane
 Capture and route to a control device. 
95 percent reduction.
 Pneumatic Controllers: Subcategory 1 (at sites with onsite power available)
 Non-emitting pneumatic controllers.
VOC and methane emission bleed rate of zero.
 Pneumatic Controllers: Subcategory 2 (at sites where onsite power is not available -continuous bleed natural gas driven)
 Installation of low-bleed pneumatic controllers.
Natural gas bleed rate no greater than 6 scfh.
 Pneumatic Controllers: Subcategory 2 (at sites where onsite power is not available -intermittent natural gas driven)
 Monitor and repair through fugitive emissions program.
OGI monitoring and repair of emissions from controller malfunctions.
 Pneumatic Controllers: Natural Gas Processing Plants. 
 Instrument air systems.
Zero natural gas bleed rate.
 Wet Seal Centrifugal Compressors (except for those located at single well sites).
 Capture and route to a control device.
95 percent reduction.
 Reciprocating Compressors (except for those located at single well sites). 
 Rod packing changeout based on annual monitoring (when measured leak rate exceeds 2 scfm). 
Replace the rod packing when measured leak rate exceeds 2 scfm based on the results of annual monitoring or route emissions from the rod packing to a process through a closed vent system under negative pressure.
 Pneumatic Pumps: Natural Gas Processing Plants.
 Instrument air systems in place of natural gas driven pumps.
Zero natural gas emissions.
 Pneumatic Pumps: Locations Other Than Natural Gas Processing Plants.
 Route to existing control device or process. 
95 percent control if there is an existing control or process on site. 95 percent control not required if 
(1) routed to an existing control that achieves less than 95 percent or (2) it is technically infeasible to route to the existing control device or process.
 Equipment Leaks at Natural Gas Processing Plants.
 LDAR with bimonthly OGI.
 LDAR with OGI following procedures in Appendix K. 
                                       
C. Costs and Benefits
	The EPA has projected the emissions reductions, benefits, and costs that may result from this proposed action. These results are presented in detail in the regulatory impact analysis (RIA) accompanying this proposal. 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. 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 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.
TABLE 4. PROJECTED EMISSIONS REDUCTIONS UNDER THE PROPOSED REQUIREMENTS, 2023-2035 TOTAL
                                   Pollutant
                    Emissions Reductions (2023-2035 Total)
Methane (million short tons)
                                     21.4
VOC (million short tons)
                                      6.8
Hazardous Air Pollutant (HAP) (million short tons)
                                      0.2
Methane (million metric tons CO2 Eq.)[a]
                                     484 
a CO2 Eq. calculated using a global warming potential of 25.
 
TABLE 5. BENEFITS, COSTS, NET BENEFITS, AND EMISSIONS REDUCTIONS OF THE PROPOSED RULE, 2023 THROUGH 2035 (DOLLAR ESTIMATES IN BILLIONS OF 2019 DOLLARS)
 
                            3 Percent Discount Rate
                            7 Percent Discount Rate
 
                                      PV
                                      EAV
                                      PV
                                      EAV
Climate Benefits[b]
                                     $29 
                                     $2.9
                                     $29 
                                     $2.9
Net Compliance Costs
                                     $6.6
                                     $0.7
                                     $5.4 
                                     $0.7 
Compliance Costs
                                     $8.9 
                                     $0.9 
                                     $7.0 
                                     $0.9
Value of Product Recovery
                                     $2.2 
                                     $0.2 
                                     $1.6 
                                     $0.2 
Net Benefits
                                      $22
                                     $2.3
                                     $24 
                                     $2.2 
                     Non-Monetized Benefits in this Table
Non-monetized climate benefits from 21.4 million short tons of methane reductions from 2023 to 2035

Health effects of PM2.5 and ozone exposure from 6.8 million short tons of VOC reductions from 2023 to 2035

Health effects of HAP exposure from 0.2 million short tons of HAP reductions from 2023 to 2035

Health effects of ozone exposure from 21.4 million short tons of methane reductions over the 2023 to 2035 period

                             Visibility impairment

                              Vegetation effects
[a] Rows may not appear to add correctly due to rounding. 		
[b] Climate benefits are based on reductions in methane emissions and are calculated using four different estimates of the social cost of methane (SC-CH4) (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent discount rate). For the presentational purposes of this table, we show the benefits associated with the average SC-CH4 at a 3 percent discount rate, but the Agency does not have a single central SC-CH4 point estimate. We emphasize the importance and value of considering the benefits calculated using all four SC-CH4 estimates; the present value (and equivalent annual value) of the additional benefit estimates range from $12 billion to $77 billion ($1.3 billion to $7.7 billion) over 2023 to 2035 for the proposed option. Please see Table 3-5 and Table 3-6 of the RIA for the full range of SC-CH4 estimates. As discussed in Chapter 3 of the RIA, a consideration of climate benefits calculated using discount rates below 3 percent, including 2 percent and lower, are also warranted when discounting intergenerational impacts. All net benefits are calculated using climate benefits discounted at 3 percent.	

II. General Information
A. Does this action apply to me?
	Categories and entities potentially affected by this action include:
         TABLE 6. INDUSTRIAL SOURCE CATEGORIES AFFECTED BY THIS ACTION
Category
NAICS Code[1]
Examples of Regulated Entities
Industry 
211120
Crude Petroleum Extraction.

211130
Natural Gas Extraction.

221210
Natural Gas Distribution.

486110
Pipeline Distribution of Crude Oil.

486210
Pipeline Transportation of Natural Gas.
Federal Government
. . . . 
Not affected.
State/local/tribal government
. . . .
Not affected.
[1] North American Industry Classification System (NAICS).
      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. Crude Oil and Natural Gas Emissions and Climate Change 
A. Impacts of GHGs, VOCs and SO2 Emissions on Public Health and Welfare
      As noted previously, the Oil and Natural Gas Industry emits a wide range of pollutants, including GHGs (such as methane and CO2), VOCs, SO2, NOX, H2S, CS2, 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 SO2.
1. Climate Change Impacts from GHGs Emissions 
      Elevated concentrations of GHGs are and have been warming the planet, leading to changes in the Earth's climate including changes in the frequency and intensity of heat waves, precipitation, and extreme weather events; rising seas; and retreating snow and ice. The changes taking place in the atmosphere as a result of the well-documented buildup of GHGs due to human activities are changing the climate at a pace and in a way that threatens human health, society, and the natural environment. Human 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 7, 2009). In the 2009 Endangerment Findings, the Administrator found under section 202(a) of the CAA that elevated atmospheric concentrations of six key well-mixed GHGs  -  CO2, CH4, N2O, hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (SF6)  -  "may reasonably be anticipated to endanger the public health and welfare of current and future generations." (74 FR 66523), 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). 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). 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). 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). Children, the elderly, and the poor are among the most vulnerable to these climate-related health effects (74 FR 66498).
      The 2009 Endangerment Findings also documented, together with the extensive scientific and technical evidence in the supporting record, that climate change touches nearly every aspect of public welfare in the U.S. with resulting economic costs, including: changes in water supply and quality due to increased frequency of drought and extreme rainfall events; increased risk of storm surge and flooding in coastal areas and land loss due to inundation; increases in peak electricity demand and risks to electricity infrastructure; and the potential for significant agricultural disruptions and crop failures (though offset to some extent by carbon fertilization). These impacts are also global and may exacerbate problems outside the U.S. that raise humanitarian, trade, and national security issues for the U.S. (74 FR 66530).
      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). 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).
      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 west along with more intense and larger wildfires. These and other trends are examples of the risks discussed the 2009 and 2016 Endangerment Findings that have already been experienced. Additionally, major scientific assessments continue to demonstrate advances in our understanding of the climate system and the impacts that GHGs have on public health and welfare both for current and future generations. These updated observations and projections document the rapid rate of current and future climate change both globally and in the U.S. These assessments include:
 U.S. Global Change Research Program's (USGCRP) 2016 Climate and Health Assessment and 2017-2018 Fourth National Climate Assessment (NCA4)[,] 
 IPCC's 2018 Global Warming of 1.5°C, 2019 Climate Change and Land, and the 2019 Ocean and Cryosphere in a Changing Climate assessments, as well as the 2021 IPCC Sixth Assessment Report (AR6). 
 The NAS 2016 Attribution of Extreme Weather Events in the Context of Climate Change, 2017 Valuing Climate Damages: Updating Estimation of the Social Cost of Carbon Dioxide, and 2019 Climate Change and Ecosystems assessments
 National Oceanic and Atmospheric Administration's (NOAA) annual State of the Climate reports published by the Bulletin of the American Meteorological Society, most recently in August of 2020.  
 EPA Climate Change and Social Vulnerability in the United States: A Focus on Six Impacts (2021).
   
      The most recent information demonstrates that the climate is continuing to change in response to the human-induced buildup of GHGs in our atmosphere. These recent assessments show that atmospheric concentrations of GHGs have risen to a level that has no precedent in recent geologic history and 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, CO2, measured at Mauna Loa in Hawaii and at other sites around the world reached 414 ppm in 2020, and has continued to rise. 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. 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.[,] The IPCC determined (with medium confidence) that this past decade was warmer than any multi-century period in at least the past 100,000 years. Global average sea level has risen by about 8 inches (about 21 centimeters (cm)) from 1901 to 2018, with the rate from 2006 to 2018 (0.15 inches/year or 3.7 millimeters (mm)/year) almost twice the rate over the 1971 to 2006 period, and three times the rate of the 1901 to 2018 period.  The rate of sea level rise over the 20th century was higher than in any other century in at least the last 2,800 years. Higher CO2 concentrations have led to acidification of the surface ocean in recent decades to an extent unusual in the past 2 million years, with negative impacts on marine organisms that use calcium carbonate to build shells or skeletons. Arctic sea ice extent continues to decline in all months of the year; the most rapid reductions occur in September (very likely almost a 13 percent decrease per decade between 1979 and 2018) and are unprecedented in at least 1000 years. Human-induced climate change has led to heatwaves and heavy precipitation becoming more frequent and more intense, along with increases in agricultural and ecological droughts in many regions. 
      The assessment literature demonstrates that modest additional amounts of warming may lead to a climate different from anything humans have ever experienced. The present-day CO2 concentration of 414 ppm is already higher than at any time in the last 2 million years. If concentrations exceed 450 ppm, they would likely be higher than any time in the past 23 million years: at the current rate of increase of more than 2 ppm a year, this would occur in about 15 years. While GHGs are not the only factor that controls climate, it is illustrative that 3 million years ago (the last time CO2 concentrations were 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 2000 years, sea level will rise by 7 to 10 feet even if warming is limited to 1.5°C (2.7°F), from 7 to 20 feet if limited to 2°C (3.6°F), and by 60 to 70 feet if warming is allowed to reach 5°C (9°F) above preindustrial levels. For context, almost all of the city of Miami is less than 25 feet above sea level, and the NCA4 stated that 13 million Americans would be at risk of migration due to 6 feet of sea level rise. Moreover, the CO2 being absorbed by the ocean has resulted in changes in ocean chemistry due to acidification of a magnitude not seen in 65 million years, putting many calcifying marine species at risk. 
      The NCA4 found that it is very likely (greater than 90 percent likelihood) that by mid-century, the Arctic Ocean will be almost entirely free of sea ice by late summer for the first time in about 2 million years. Coral reefs will be at risk for almost complete (99 percent) losses with 1°C (1.8°F) of additional warming from today (2°C or 3.6°F since preindustrial). At this temperature, between 8 and 18 percent of animal, plant, and insect species could lose over half of their climatic ranges, and 7 to 10 percent of rangeland livestock would be projected to be lost. 
      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 an "extreme heatwave" is as warm or warmer than the 2003 Paris heatwave, and an "exceptional heatwave" is as warm or warmer than the 2010 Russian heatwave). 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 be committed to thawing. 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. 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 tropica cyclones more damaging. 
      The NCA4 also evaluated a number of impacts specific to the U.S. Severe drought and outbreaks of insects like the mountain pine beetle have killed 100s of millions of trees in the western U.S. Wildfires have burned more than 3.7 million acres in 14 of the 17 years between 2000 and 2016, and Federal wildfire suppression costs were about a billion dollars annually. The National Interagency Fire Center has documented U.S. wildfires since 1983, and the ten years with the largest acreage burned have all occurred since 2004. Wildfire smoke degrades air quality increasing health risks, and more frequent and severe wildfires due to climate change would further diminish air quality, increase incidences of respiratory illness, impair visibility, and disrupt outdoor activities. 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. The Congressional Budget Office estimated that climate change impacts could reduce national GDP by 1% in 2050, though they cautioned that they had made an incomplete accounting of impacts.  
      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) and cause ocean acidification. Nitrous oxide depletes the levels of protective stratospheric ozone. 
      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. 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. Methane has a high radiative efficiency  -  almost 30 times that of carbon dioxide per ppb (and therefore, 80 times as much per unit mass). In addition, methane contributes to climate change through chemical reactions in the atmosphere that produce tropospheric ozone and stratospheric water vapor. Human emissions of methane are responsible for about one third of the warming due to well-mixed GHGs, the second most important human warming agent after carbon dioxide. Because of the substantial emissions of methane, and its radiative efficiency, methane mitigation is one of the best opportunities for reducing near term warming. 
      The tropospheric ozone produced by the reaction of methane in the atmosphere has harmful effects for human health and plant growth in addition to its climate effects. In remote areas, methane is a dominant precursor to tropospheric ozone formation. Approximately 50 percent of the global annual mean ozone increase since preindustrial times is believed to be due to anthropogenic methane. Projections of future emissions also indicate that methane is likely to be a key contributor to ozone concentrations in the future. Unlike NOX and VOC, which affect ozone concentrations regionally and at hourly time scales, methane emissions affect ozone concentrations globally and on decadal time scales given methane's long atmospheric lifetime when compared to these other ozone precursors. Reducing methane emissions, therefore, will contribute to efforts to reduce global background ozone concentrations that contribute to the incidence of ozone-related health effects.[ ]The benefits of such reductions are global and occur in both urban and rural areas. 
      These scientific assessments 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) 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 NOX in the presence of sunlight. Ozone formation can be controlled to some extent through reductions in emissions of the ozone precursors VOC and NOX. 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.
      Scientific evidence also shows that repeated exposure to ozone can reduce growth and have other harmful effects on sensitive plants and trees. These types of effects have the potential to impact ecosystems and the benefits they provide.
3. SO2 
      Current scientific evidence links short-term exposures to SO2, ranging from 5 minutes to 24 hours, with an array of adverse respiratory effects including bronchoconstriction and increased asthma symptoms. These effects are particularly important for asthmatics at elevated ventilation rates (e.g., while exercising or playing).  
      Studies also show an association between short-term exposure and increased visits to emergency departments and hospital admissions for respiratory illnesses, particularly in at-risk populations including children, the elderly, and asthmatics.
      SO2 in the air can also damage the leaves of plants, decrease their ability to produce food  -  photosynthesis  -  and decrease their growth. In addition to directly affecting plants, SO2, when deposited on land and in estuaries, lakes, and streams, can acidify sensitive ecosystems resulting in a range of harmful indirect effects on plants, soils, water quality, and fish and wildlife (e.g., changes in biodiversity and loss of habitat, reduced tree growth, loss of fish species). Sulfur deposition to waterways also plays a causal role in the methylation of mercury.
B. 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 operations as being generally composed of four segments: (1) extraction and production of crude oil and natural gas ("oil and natural gas production"), (2) natural gas processing, (3) natural gas transmission and storage, and (4) natural gas distribution.[,]  The EPA regulates oil refineries as a separate source category; accordingly, as with the previous oil and gas NSPS rulemakings, for purposes of this 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."
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. 
      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, H2S, CO2, helium, and nitrogen. Ethane, propane, butane, isobutane, and pentane are all considered NGL and often are sold separately for a variety of different uses. Natural gas with high methane content is referred to as "dry gas," while natural gas with significant amounts of ethane, propane, or butane is referred to as "wet gas." Natural gas 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 CO2 removal, fractionation of NGL, and other processes, such as the capture of CO2 separated from natural gas streams for delivery outside the facility. 
c. Transmission and Storage Segment
      Once natural gas processing is complete, the resulting natural gas exits the natural gas process plant and enters the transmission and storage segment where it is transmitted to storage and/or distribution to the end user.  
      Pipelines in the natural gas transmission and storage segment can be interstate pipelines, which carry natural gas across state boundaries, or intrastate pipelines, which transport the gas within a single state. Basic components of the two types of pipelines are the same, though interstate pipelines may be of a larger diameter and operated at a higher pressure. To ensure that the natural gas continues to flow through the pipeline, the natural gas must periodically be compressed, thereby increasing its pressure. Compressor stations perform this function and are usually placed at 40- to 100-mile intervals along the pipeline. At a compressor station, the natural gas enters the station, where it is compressed by reciprocating or centrifugal compressors. 
      Another part of the transmission and storage segment are aboveground and underground natural gas storage facilities. Storage facilities hold natural gas for use during peak seasons. The main difference between underground and aboveground storage sites is that storage takes place in storage vessels constructed of non-earthen materials in aboveground storage. Underground storage of natural gas typically occurs in depleted natural gas or oil reservoirs and salt dome caverns. One purpose of this storage is for load balancing (equalizing the receipt and delivery of natural gas). At an underground storage site, typically other processes occur, including compression, dehydration, and flow measurement. 
d. Distribution Segment
      The distribution segment provides the final step in delivering natural gas to customers. The natural gas enters the distribution segment from delivery points located on 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 "citygate." Natural gas distribution systems consist of thousands of 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, which allow distribution companies to monitor the natural gas as it flows through the system. 
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. 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 CO2, and over a 20-year timeframe, it is 83 times more powerful. 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, on 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, SO2, NOX, H2S, CS2, and COS. 
      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 industry 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 CO2 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. There are a number of definitions for the term "super-emitter." A 2018 National Academies of Sciences, Engineering, and Medicine report on methane discussed three categories of "high-emitting" sources: 
 Routine or "chronic" high-emitting sources, which regularly emit at higher rates relative to "peers" in a sample. Examples include large facilities or large emissions 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 occur in a sporadic and unpredictable manner due to 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.
      Super-emitters have been observed at many different scales from site-level to component-level across many research studies. Studies will often develop a study-specific definition such as a top percentile of emissions in a study population (e.g., top 10 percent), emissions exceeding a certain threshold (e.g., 26 kg/day), emissions over a certain detection threshold (e.g., 1-3 g/s) or as facilities with the highest proportional emission rate. For many equipment types and activities, the EPA's GHG emission estimates include the full range of conditions, including "super-emitters." For other situations, where data are available, emissions estimates for abnormal events are calculated separately and included in the Inventory of U.S. Greenhouse Gas Emissions and Sinks ("GHGI") (e.g., Aliso Canyon leak event). Given the variability of practices and technologies across oil and gas systems and the occurrence of episodic events, it is possible that the EPA's estimates do not include all methane emissions from abnormal events. The EPA continues to 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-emitting events and fugitive emissions, using lower emitting equipment where feasible, and employing best management practices will not only reduce emissions but reduce the loss of revenue from this valuable commodity. 
      Below we provide estimated emissions of methane, VOC, and SO2 from Oil and Natural Gas Industry operation sources.
      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. 
TABLE 7. U.S. METHANE EMISSIONS BY SECTOR (MILLION METRIC TONS CARBON DIOXIDE EQUIVALENT (MMT CO2 EQ.))
Sector 
                                     1990
                                     2010
                                     2019
Oil and Natural Gas Production, and Natural Gas Processing and Transmission and Storage
                                      189
                                      176
                                      182
Landfills
                                     177 
                                     124 
                                     114 
Enteric Fermentation
                                     165 
                                     172 
                                     179 
Coal Mining
                                      96 
                                      82 
                                      47 
Manure Management
                                      37 
                                      55 
                                      62 
Other Oil and Gas Sources
                                      46
                                      17
                                      15
Wastewater Treatment
                                      20 
                                      19 
                                      18 
Other Methane Sources
                                      46 
                                      47 
                                      42 
Total Methane Emissions
                                     777 
                                     692 
                                     660 
Emissions from the Inventory of United States Greenhouse Gas Emissions and Sinks: 1990-2019 (published April 14, 2021), calculated using GWP of 25. Note: Totals may not sum due to rounding.

      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 CO2 Eq. (or million metric tons CO2 Eq.) of methane. 
TABLE 8. U.S. METHANE EMISSIONS FROM NATURAL GAS AND PETROLEUM SYSTEMS (MMT CO2 EQ.)
Sector 
                                     1990
                                     2010
                                     2019
Natural Gas Production
                                      63
                                      97
                                      94
Natural Gas Processing
                                      21
                                      10
                                      12
Natural Gas Transmission and Storage
                                      57
                                      30
                                      37
Petroleum Production
                                      48
                                      39
                                      38
Emissions from the Inventory of United States Greenhouse Gas Emissions and Sinks: 1990-2019 (published April 14, 2021), calculated using GWP of 25. Note: Totals may not sum due to rounding.

      Global GHG Emissions. For additional background information and context, we used 2018 World Resources Institute Climate Watch data to make comparisons between U.S. oil and natural gas production and natural gas processing and transmission and storage emissions and the emissions inventories of entire countries and regions. The U.S. methane emissions from oil and natural gas production and natural gas processing and transmission and storage constitute 0.4 percent of total global emissions of all GHGs (48,601 MMT CO2 Eq.) from all sources. 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. 
      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 CO2 emissions, reaching at least net zero CO2 emissions, along with strong reductions in other GHG emissions." The report also singled out the importance of "strong and sustained CH4 emission reductions" in part due to the short lifetime of methane leading to the near-term cooling from reductions in methane emissions offsetting the unmasking of warming due to reductions in SO2 and other aerosols. 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 SO2 emissions are developed by the EPA for the National Emissions Inventory (NEI), for which states are required to submit information under 40 CFR part 51, subpart A. Data in the NEI may be organized by various data points, including sector, NAICS code, and Source Classification Code. The oil and natural gas sources emit 5.8 and 2.4 percent of U.S. VOC and SO2, respectively. Tables 9 and 10 below present total U.S. VOC and SO2 emissions by sector, respectively, for the year 2017, in kilotons (kt) (or thousand metric tons). 
                  TABLE 9. U.S. VOC EMISSIONS BY SECTOR (kt)
Sector 
2017
Biogenics  -  Vegetation and Soil
25,823
Fires  -  Wildfires
4,578
Oil and Natural Gas Production, and Natural Gas Processing and Transmission
2,504
Fires  -  Prescribed Fires
2,042
Solvent  -  Consumer and Commercial Solvent Use
1,610
Mobile  -  On-Road non-Diesel Light Duty Vehicles
1,507
Mobile  -  Non-Road Equipment  -  Gasoline
1,009
Other VOC Sources
4,045
Total VOC Emissions
43,118
Emissions from the 2017 NEI (released April 2020). Note: Totals may not sum due to rounding.
                                       
                  TABLE 10. U.S. SO2 EMISSIONS BY SECTOR (kT)
Sector 
2017
Fuel Combustion  -  Electric Generation  -  Coal
1,319
Fuel Combustion  -  Industrial Boilers, Internal Combustion Engines  -  Coal
212
Mobile  -  Commercial Marine Vessels
183
Industrial Processes  -  Not Elsewhere Classified
138
Fires  -  Wildfires
135
Industrial Processes  -  Chemical Manufacturing
123
Oil and Natural Gas Production and Natural Gas Processing and Transmission
65
Other SO2 Sources
551
Total SO2 Emissions
2,726
Emissions from the 2017 NEI (released April 2020). Note: Totals may not sum due to rounding.
                                       
      Table 11 below presents total VOC and SO2 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 SO2 emissions have been declining in just about every anthropogenic sector, but the oil and gas sector is an exception where SO2 emissions have been slightly increasing or remaining steady in some cases in recent years.
TABLE 11. U.S. VOC AND SO2 EMISSIONS FROM NATURAL GAS AND PETROLEUM SYSTEMS (kt)
Sector 
                                      VOC
                                      SO2
Oil and Natural Gas Production
                                     2,478
                                      41
Natural Gas Processing
                                      12
                                      23
Natural Gas Transmission and Storage
                                      14
                                       1
Emissions from the 2017 NEI, (published April 2020), in kt (or thousand metric tons). Note: Totals may not sum due to rounding.

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 for the 2016 Rule, the U.S. Court of Appeals for the District of Columbia Circuit (the D.C. Circuit) has stated that in light of this provision, the EPA may not adopt a standard the cost of which would be "exorbitant," "greater than the industry could bear and survive," "excessive," or "unreasonable." These formulations appear to be synonymous, and for convenience, in this rulemaking, as in previous rulemakings, we will 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). 
      CAA section 111(a) does not provide specific direction regarding what metric or metrics to use in considering costs, affording the EPA considerable discretion in choosing a means of cost consideration. In this rulemaking, we evaluated whether a control cost is reasonable under a number of approaches that we find appropriate for assessing the types of controls at issue. For example, 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. 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.  
      The standard that the EPA develops, based on the BSER, is commonly a numerical emissions limit, expressed as a performance level (typically, a rate-based standard). CAA section 111(b)(5) precludes the EPA from prescribing a particular technological system that must be used to comply with a standard of performance. Rather, sources can select any measure or combination of measures that will achieve the standard.
      CAA section 111(h)(1) authorizes the Administrator to promulgate "a design, equipment, work practice, or operational standard, or combination thereof" if in his or her judgment, "it is not feasible to prescribe or enforce a standard of performance." CAA section 111(h)(2) provides the circumstances under which prescribing or enforcing a standard of performance is "not feasible," such as, when the pollutant cannot be emitted through a conveyance designed to emit or capture the pollutant, or when there is no practicable measurement methodology for the particular class of sources. CAA section 111(b)(1)(B) requires the EPA to "at least every 8 years review and, if appropriate, revise" performance standards unless the "Administrator determines that such review is not appropriate in light of readily available information on the efficacy" of the standard. 
      As mentioned above, once the EPA lists a source category under CAA section 111(b)(1)(A), CAA section 111(b)(1)(B) provides the EPA discretion to determine the pollutants and sources to be regulated. In addition, concurrent with the 8-year review (and though not a mandatory part of the 8-year review), the EPA may examine whether to add standards for pollutants or emission sources not currently regulated for that source category.
      Once the EPA establishes NSPS in a particular source category, the EPA is required in certain circumstances to issue EG to reduce emissions from existing sources in that same source category. Specifically, CAA section 111(d) requires that the EPA prescribe regulations to establish procedures under which states submit plans to establish, implement, and enforce standards of performance for existing sources for certain air pollutants to which a Federal NSPS would apply if such existing source were a new source. The EPA addresses this CAA requirement both through its promulgation of general implementing regulations for 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 pt. 60, subpart Ba). 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) 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). 
 	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 pt. 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. 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). 
      Designated facilities located in Indian country would not be addressed by a state's CAA section 111(d) plan. Instead, an eligible tribe that has one or more designated facilities located in its area of Indian country would have the opportunity, but not the obligation, to seek authority and submit a plan that establishes standards of performance for those facilities on its tribal lands. If a tribe does not submit a plan, or if the EPA does not approve a tribe's plan, then the EPA has the authority to establish a federal plan for that tribe.
B. What is the regulatory history and litigation background of NSPS and EG for the oil and natural gas industry?
1. 1979 Listing of Source Category 
      Subsequent to the enactment of the CAA of 1970, the EPA took action to develop standards of performance for new stationary sources as directed by Congress in CAA section 111. By 1977, the EPA had promulgated NSPS for a total of 27 source categories, while NSPS for an additional 25 source categories were then under development. However, in amending the CAA that year, Congress expressed dissatisfaction that the EPA's pace was too slow. Accordingly, the 1977 CAA Amendments included a new subsection (f) in section 111, which specified a schedule for the EPA to list additional source categories under CAA section 111(b)(1)(A) and prioritize them for regulation under CAA section 111(b)(1)(B).  
      In 1979, as required by CAA section 111(f), the EPA published a list of source categories, which included "Crude Oil and Natural Gas Production," for which the EPA would promulgate standards of performance under CAA section 111(b). See Priority List and Additions to the List of Categories of Stationary Sources, 44 FR 49222 (August 21, 1979) ("1979 Priority List"). That list included, in the order of priority for promulgating standards, source categories that the EPA Administrator had determined, pursuant to CAA section 111(b)(1)(A), contribute significantly to air pollution that may reasonably be anticipated to endanger public health or welfare. See 44 FR 49223 (August 21, 1979); see also 49 FR 2636-37 (January 20, 1984).
2. 1985 NSPS for VOC and SO2 Emissions from Natural Gas Processing 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 SO2 emissions from onshore natural gas processing plants (40 CFR part 60, subpart LLL).
3. 2012 NSPS OOOO Rule and Related Amendments
      In 2012, pursuant to its duty under CAA section 111(b)(1)(B) to review and, if appropriate, revise the 1985 NSPS, the EPA published the final rule, "Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution," 77 FR 49490 (August 16, 2012) (40 CFR part 60, subpart OOOO) ("2012 NSPS OOOO"). The 2012 rule updated the SO2 standards for sweetening units and the VOC standards for equipment leaks at onshore natural gas processing plants. In addition, it established VOC standards for several oil and natural gas-related operations emission sources not covered by 40 CFR part 60, subparts KKK and LLL, including natural gas well completions, centrifugal and reciprocating compressors, certain natural gas 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 NSPS OOOOa"). [,] The 2016 NSPS OOOOa rule established NSPS for sources of GHGs and VOC emissions for certain equipment, processes, and operations across the Oil and Natural Gas Industry, including in the transmission and storage segment. 81 FR 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 predicate the GHGs NSPS on a finding that GHGs 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 in making the rational basis determination. 81 FR at 35843.  
      Specifically, the 2016 NSPS OOOOa addresses the following emission sources: 
      *	Sources that were unregulated under the 2012 NSPS OOOO (hydraulically fractured oil well completions, pneumatic pumps, and fugitive emissions from well sites and compressor stations); 
      *	Sources that were regulated under the 2012 NSPS OOOO for VOC emissions, but not for GHG emissions (hydraulically fractured gas well completions and equipment leaks at natural gas processing plants); and 
      *	Certain equipment that is used across the source category, of which the 2012 NSPS OOOO regulated emissions of VOC from only a subset (pneumatic controllers, centrifugal compressors, and reciprocating compressors, with the exception of those compressors located at well sites). 
      On March 12, 2018, 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. 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.
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.  
      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 EO 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. 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.
C. Congressional Review Act (CRA) Joint Resolution of Disapproval 
On June 30, 2021, the President signed into law a joint resolution of Congress, S.J. Res. 14, adopted under the CRA, disapproving the 2020 Policy Rule. By the terms of the CRA, the signing into law of the CRA joint resolution of disapproval means that the 2020 Policy Rule is "treated as though [it] had never taken effect." 5 U.S.C. 801(f). As a result, the VOC and methane standards for the transmission and storage segment, as well as the methane standards for the production and processing segments  -  all of which had been rescinded in the 2020 Policy Rule -- remain in effect. In addition, the EPA's authority and obligation to 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.
      As described in greater detail in section VIII, by disapproving the 2020 Policy Rule with enactment of the CRA resolution, Congress expunged the regulatory rescissions and statutory interpretations of the 2020 Policy Rule and restored the regulatory requirements in the 2016 NSPS OOOOa Rule. By this action, Congress also reinstated the statutory interpretations the EPA propounded in support of the 2016 NSPS OOOOa Rule and the EPA's 2016 decision to regulate methane emissions from the Crude Oil and Natural Gas sector. Congress provided included in the legislative history for the CRA resolution in the form of a detailed discussion explaining the effects of the CRA resolution. H.R. Rep. No. 117-64, 7-8 (2021) (House Report); 167 Cong. Rec. S2282-83 (April 28, 2021) (statement by Sen. Heinrich) (Senate Statement). The legislative history made clear that Congress' enactment of the resolution reflected its view that the EPA's regulation of methane emissions from the Oil and Natural Gas Industry  -  including both new and existing sources - is critically important. House Report at 3, Senate Statement at S2283. In addition, the legislative history explained that the 2016 NSPS OOOOa Rule was correct in determining that the transmission and storage segment should be included in the Crude Oil and Natural Gas source category on the grounds stated in that rule, and the 2020 Policy Rule was incorrect in rescinding that determination. House Report at 3, Senate Statement at S2283. The House Report further explained that the 2016 NSPS OOOOa Rule was correct in interpreting CAA section 111 to authorize the EPA to promulgate NSPS for GHG emissions as long as the EPA has a rational basis for doing so; and that the 2020 Policy Rule was incorrect both in asserting that regulation of methane was redundant to regulation of VOCs and in interpreting section 111 to require, or at least authorize EPA to require, a pollutant-specific significant-contribution finding, supported by a standard or criteria. House Report at 8-12, see Senate Statement at S2283. 
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
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. 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. 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.
	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 and the North Slope Borough of Alaska. BOEM also has air jurisdiction in Federal waters on the Outer Continental Shelf 3-9 miles offshore (depending on state) and beyond. The Outer Continental Shelf Lands Act (OCSLA) section 5(a)(8) states, "The Secretary of the Interior is authorized to prescribe regulations `for compliance with the national ambient air quality standards pursuant to the CAA . . . to the extent that activities authorized under [the Outer Continental Shelf Lands Act] significantly affect the air quality of any State.'" The EPA and states have the air jurisdiction onshore and in state waters, and the EPA has air jurisdiction offshore in certain areas. More detailed information can be found at BOEM's website: https://www.boem.gov/.  
      The U.S. Department of Transportation (DOT) manages the U.S. transportation system. Within DOT, the Pipeline and Hazardous Materials Safety Administration (PHMSA) is responsible for regulating and ensuring the safe and secure transport of energy and other hazardous materials to industry and consumers by all modes of transportation, including pipelines. While PHMSA has focused on human safety which likely has environmental co-benefit, 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, expressly requires consideration of environmental safety and protection of the environment in several sections. 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. In addition, the PIPES Act of 2020 contains several provisions that specifically address the minimization of releases of natural gas from pipeline facilities, such as a mandate that the Secretary of Transportation promulgate regulations related to gas pipeline LDAR programs. More detailed information can be found at PHMSA's website: https://www.phmsa.dot.gov/. 
      The U.S. Department of Energy (DOE) develops oil and natural gas policies and funds research on advanced fuels and monitoring and measurement technologies. Specifically, the Advanced Research Projects Agency-Energy (ARPA-E) program advances high-potential, high-impact energy technologies that are too early for private-sector investment. APRA-E awardees are unique because they are developing entirely new technologies. More detailed information can be found at ARPA-E's website: https://arpa-e.energy.gov/. Also, the U.S. Energy Information Administration (EIA) compiles data on energy consumption, prices, including natural gas, and coal. More detailed information can be found at the EIA's website: https://www.eia.gov/.  
      The U.S. Federal Energy Regulatory Commission (FERC) is an independent agency that regulates the interstate transmission of electricity, natural gas, and oil. FERC also reviews proposals to build liquefied natural gas terminals and interstate natural gas pipelines 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/.
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. 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 reducing pressures for potential new regulations or helping shape future regulations.[,] 
	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. This program includes nearly 70 companies from all segments of the industry -- production, gathering and boosting, transmission and storage, and distribution -- however 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 vulnerable communities and organizations that may represent environmental justice issues. 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.
      EO 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, EO 13985 was signed to advance racial equity and support underserved communities through Federal government actions. 86 FR 7009 (January 20, 2021). 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. 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; 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. 
      Scientific assessment reports produced over the past decade by the USGCRP,[,] the (IPCC),[,][,][,], the National Academies of Science, Engineering, and Medicine[,], and the EPA add more evidence that the impacts of climate change raise potential EJ concerns. These reports conclude that poorer or predominantly non-White communities can be especially vulnerable to climate change impacts because they tend to have limited adaptive capacities and 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, may be uniquely vulnerable to climate change health impacts in the U.S. In particular, the 2016 scientific assessment on the Impacts of Climate Change on Human Health 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. 
      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." 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.
      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 crews and agricultural laborers, who frequently are comprised 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. Finally, resiliency and adaptation are more difficult for economically disadvantaged communities: They have less liquidity, individually and collectively, to move or to make the types of infrastructure or policy changes to limit or reduce the hazards they face. They frequently are less able to self-advocate for resources that would otherwise aid in resiliency and hazard reduction and mitigation. 
      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 at certain 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 heat waves, 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.
      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 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.  
      Impacts of Climate Change on Native American Tribal Nations. Native American Tribal nations face disproportionate risks from the impacts of climate change, particularly those impacted by degradation of natural and cultural resources within established reservation boundaries and threats to traditional subsistence lifestyles. Tribal 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. 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. In addition, there can be institutional barriers to their management of water, land, and other natural resources that could impede adaptive measures.
      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. NCA4 noted that Indigenous peoples often have disproportionately higher rates of asthma, cardiovascular disease, Alzheimer's, diabetes, and obesity, which can all contribute to increased vulnerability to climate-driven extreme heat and air pollution events. These factors also may be exacerbated by stressful situations, such as extreme weather events, wildfires, and other circumstances.
      NCA4 and IPCC's Fifth Assessment Report also highlighted several impacts specific to Alaskan Indigenous Peoples. Coastal erosion and permafrost thaw will lead to more coastal erosion, exacerbated risks of winter travel, and 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. 
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 EO 12898 (59 FR 7629, February 16, 1994) and referenced in EO 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.
      For all demographic groups except Hispanic/Latino and people aged 0-17, the percentage of people with estimated risks above the specified levels is at or below the national average. The percent minority is about the same as the national average, but the Hispanic/Latino demographic group 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.
      TABLE 12. CANCER RISK AND DEMOGRAPHIC POPULATION ESTIMATES FOR 2017 NEI NONPOINT OIL AND NATURAL GAS EMISSIONS

Risks >= 100-in-1 million

Risks >= 50-in-1 million

Risks > 1-in-1 million

Nationwide

                                       
                                       
                                       

Total Population
                                    39,000
                                       
                                    143,000
                                       
                                   6,805,000
                                       

Population
%
Population
%
Population
%
%
Minority
13,268
34.1
52,154
36.5
2,010,161
29.5
39.9
African American
140
0.4
1,434
1.0
535,055
7.9
12.2
Native American
77
0.2
465
0.3
59,087
0.9
0.7
Other and Multiracial
1,443
3.7
5,148
3.6
323,397
4.8
8.2
Hispanic or Latino
11,608
29.9
45,107
31.6
1,092,621
16.1
18.8
Age 0-17
10,679
27.5
37,487
26.2
1,463,907
21.5
22.6
Age >= 65
4,272
11.0
17,188
12.0
1,085,067
15.9
15.7
Below the Poverty Level
2,000
5.1
13,455
9.4
902,472
13.2
13.4
Over 25 Without a High School Diploma
2,788
7.2
11,320
7.9
488,372
7.2
12.1
Linguistically 
Isolated
808
2.1
4,418
3.1
179,739
2.6
5.4

      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. 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 distributional impacts on employment and household energy burden.  For the distribution of employment effects, we assessed the demographic characteristics of workers in the oil and gas sector and of people living in oil and gas intensive communities.  We found that workers in the oil and gas sector have higher incomes, are more likely to have attended four years of high school, and are more likely to be non-white Hispanics than other people.  We found that people in oil and gas intensive communities have demographic characteristics similar to people in non-oil and gas intensive communities on average.  People in some oil and gas intensive communities have below average rates of these demographic characteristics (income, four years of high school, or fraction of the population that is non-white Hispanics).  These communities are concentrated in Texas, Oklahoma, and Louisiana.
      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.
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. 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.[,] 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.
      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 fracking 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 fracking. 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 fracking information to use tap water "at your own risk" in English.
      In addition to the trainings and listening sessions, the EPA engaged with community leaders potentially impacted by this proposed action by hosting an EJ Engagement 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. Some of the concerns from 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. 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. 
      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. 
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; 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. 
      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 and tribal nations. 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.
      As noted above, the EPA also heard from a broad range of stakeholders during virtual public listening sessions on for small business stakeholders and tribal nations on June 15 through June 17, 2021, and had a total of 173 speakers and YouTube views of more than 1,200 as of September 1, 2021.  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 tighten 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.
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 that flaring of associated gas is not required to be permitted and stated that 75 percent of flaring in Texas is not required to be permitted. 
      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 the 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 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. 
      Wells and Storage. 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. Stakeholders also focused on marginal wells and asked the EPA to consider that system-wide reductions be allowed, for example, at the basin level, and expressed challenges of retrofitting existing well sites and low production well sites. Some speakers raised concern about the safety and integrity of natural gas storage facilities and incidences of the overpressure of wells versus the design of separation and storage and the need to make sure 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.
      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.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. 
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 in emissions reduction requirements, 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. 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.
      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 this information is 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. 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. All stakeholders have a leadership role in mitigating GHGs and VOC emissions from the Crude Oil and Natural Gas source category. 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. 
      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 emerging technologies and section XIII for solicitations for comments on additional emission sources. 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.
 VIII. Legal Basis for Proposal
      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.
      Today's 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 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 it was not authorized to regulate the transmission and storage segment or to regulate methane. In 2021, Congress adopted a joint resolution to disapprove the EPA's 2020 rule under the CRA. According to the terms of CRA, the 2020 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 (House 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." House Report at 3-5. 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." Senate Statement at S2283. The Senators concluded with a stark statement:: "The welfare of our planet and of our communities depends on it." Id.
       Today's 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 at 3584. 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 In addition, in this action, we are reaffirming those determinations as clearly authorized under any reasonable interpretation of section 111.
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 at 35832. 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 required a significant-contribution analysis only when EPA regulated 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 at 35,842. 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 35,843, 35,877. 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 rule stated that it "contains two main actions," 85 FR at 57019, 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 CRA resolution 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 emissions guidelines 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 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 at 57029 (2020 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 at 35832 (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 at 35832. 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 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 at 57033, 57035-38.
      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 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 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, a 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 correct statutory interpretation, 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"). 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.
      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.
      The House Report also expressly disapproved of the 2020 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 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 gives further content to Congress's disapproval and the bar on substantially similar rulemaking. In the legislative history of the CRA, discussed above, Congress explained that it acted both to reverse the EPA's action in the 2020 rule and to reject the statutory interpretations that led the EPA to the disapproved result, and that it 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. .
      EPA is now proceeding to propose additional requirements to reduce emissions from oil and gas sources, which health and environmental considerations mandate.  While EPA fully agrees with the action that Congress took, for the reasons discussed next, the EPA would reject the positions taken in the 2020 rule and reaffirm the positions the Agency took in the 2016 rule even absent the joint resolution of disapproval.
C. Affirming the Legal Interpretations in the 2016 NSPS OOOOa Rule
      The Agency has reviewed all of the information and analyses in the 2016 and 2020 rules, and fully reaffirms the positions it took in the 2016 rule and rejects the positions taken in the 2020 rule. 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 is proposing action now to affirm the 2016 rule, including its statutory interpretations and grounds, and reject the 2020 Policy rule, including its statutory interpretations and grounds. 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.  
      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 at 35832. The 2020 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 at 57028, 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 Rule pointed out, 85 FR at 57029, 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 at 35832, underscoring the interrelated functionality of the segments. 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 from diverse industries. See 40 CFR Subpart DB (industrial-commercial-institutional steam generating units), 40 CFR 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 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 was fully justified in promulgating 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. [Would be best if OAR added a few sentences explanation] 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 at 35842-43. The EPA is not reopening those determinations for comment in the present rulemaking.
      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 2016 rule's determination that the EPA had a rational basis to regulate methane emissions from the source category due to their large contribution to dangerous air pollution means that it would be 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 -- that 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) as long as the EPA has a rational basis for doing so. 81 FR at 35842. The 2016 rule noted the precedent in prior agency actions for this position. 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 NOx, SO2 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 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 apply the rational basis standard, 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 rule's objections to the rational basis standard on grounds that is "vague and not guided by any statutory criteria," 85 FR at 57034, 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 oxides of nitrogen, sulfur dioxide and carbon monoxide from lime plants); 80 FR 64510, 64530 (Oct. 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. 
       The EPA also affirms that a facts-and-circumstances test, for this type of action, is fully appropriate, and rejects the 2020 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 a facts-and-circumstances approach. 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. [Placeholder: OAR? Discuss large amount of emissions from, and large numbers of, existing sources in the oil and gas industry.]
      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); 59 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). American Lung Assoc. v. EPA, 985 F3d 914, 977-988 (D.C. Cir. 2021). 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 [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER]. 
      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). While CAA section 111 requires that the EPA consider cost in determining such system (i.e., ``BSER''), it does not prescribe any criteria for such consideration. The D.C. Circuit has long recognized that "[CAA] section 111 does not set forth the weight that should be [sic] 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"). Also, in Essex Chem. 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. 
      Despite having "considerable discretion under [CAA] section 111," Lignite Energy Council, 198 F.3d at 933, the EPA nevertheless sought guidance in relevant case law and noted that, in several cases, the D.C. Circuit has shed light on how the EPA is to consider cost under CAA section 111(a)(1). For example, in Essex Chemical, 486 F.2d at 433, 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.'' The court has reiterated this limit in subsequent case law, including Lignite Energy Council, 198 F.3d at 933, in which it stated: ``EPA's choice will be sustained unless the environmental or economic costs of using the technology are exorbitant.'' In Portland Cement Ass'n v.Train, 513 F.2d 506, 508 (D.C. Cir. 1975), the court elaborated by explaining that the inquiry is whether the costs of the standard are ``greater than the industry could bear and survive.'' In Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981), the court provided a substantially similar formulation of the cost factor when it held: ``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.'' 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 DC 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. 
       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. A cost-effectiveness analysis is one 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 GHG (methane) emissions from existing sources in the Crude Oil and Natural Gas source category. Increasingly, however, 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 may be employed. Consequently, there is a need for determining cost-effectiveness for a control option across multiple pollutants (or classes of multiple pollutants). Further, both methane and VOC are reduced in equal proportions simultaneously when controlled. During the rulemaking for NSPS OOOOa, we evaluated a number of approaches for considering the costs of the available multipollutant controls for reducing both methane and VOC emissions. One approach was to assign the entire annualized cost to the reduction in emissions of a single pollutant reduced by the multipollutant control option and treat the simultaneous reductions of the other pollutants as incidental. This was the approach we took in the 2012 NSPS, but we found it inappropriate for the 2016 NSPS OOOOa and similarly inappropriate now for the proposed NSPS OOOOb because methane and VOCs are both directly regulated and, therefore, neither reduction should be considered incidental under NSPS OOOOa and its proposed update (NSPS OOOOb). Under these circumstances, we believe it is most appropriate to evaluate the cost-effectiveness of abating both pollutants when determining BSER. 
       One approach to doing so is to allocate all of the annualized costs to each of the pollutant emission reductions addressed by the multipollutant control option. Unlike the approach taken in the 2012 NSPS, where the cost effectiveness of control options reducing methane emissions was not calculated, this approach evaluates the cost-effectiveness of control options reducing each pollutant based upon the full cost of the control. Under this approach, the control option is considered cost effective only if emission reduction for each pollutant is considered cost effective based on the full cost of control. However, this approach, by assuming that each pollutant bears the entire cost, inflates the control cost by the multiple of the number of additional pollutants being reduced. This type of approach therefore over-estimates the cost of obtaining emissions reductions with a multipollutant control as it does not recognize the simultaneity of the reductions achieved by the application of the control option. For that reason, we did not consider it appropriate to apply this approach for NSPS OOOOa and, for the same reason, we do not think it is appropriate to do so for the proposed NSPS OOOOb.
       Another type of approach allocates the annualized cost to the sum of the individual pollutant emission reductions addressed by the multipollutant control option. The multipollutant cost-effectiveness approach may be appropriate when each of the pollutant reductions is similar in value or impact. However, methane and VOC have quite different health and environmental impacts. Summing the pollutants to derive the denominator of the cost-effectiveness equation is inappropriate for this reason. Similarly, if the multiple pollutants could be combined with like units -- for example, via economic valuation -- the pollutants could be summed. Therefore, we did not use this approach for NSPS OOOOa; for the same reason, we think that this approach would be inappropriate here for the proposed NSPS OOOOb.
      For NSPS OOOOa, we used two types of approaches for considering the cost of reducing emissions from multiple pollutants using one control; we are proposing to use these same two approaches along with other factors in considering the cost of requiring control for NSPS OOOOb. One approach, which we refer to in this action 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 emissions 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. Unlike the approach in 2012, this approach acknowledges the reductions of methane emissions is intended as opposed to incidental. It also reflects the actual overall cost of the control. 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. It also does not require the combination of methane and VOC emission reductions into a single number, which is not appropriate as discussed immediately above. In addition, this approach is simple and straightforward in application: if the multipollutant control is cost-effective for reducing emissions of either of the targeted pollutant, 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. For example, in this proposal, both methane and VOC emissions 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, half of the control costs are allocated to methane, the other half to VOC. Under this approach, control is cost effective if it is cost effective for both VOC and methane. This approach similarly does not inflate the control cost nor does it require the combination of methane and VOC emission reductions into a single number. 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. As such, in our analyses 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. The EPA recognizes, however, not all situations where multipollutant controls are applied are the same, and that other types of approaches, including those described above as inappropriate for this action, might be appropriate in other instances. 
       In section XII, which describes the BSER analyses for individual affected facilities, the EPA identifies available control options based on its review of various sources of information, including the RACT/BACT/LAER Clearinghouse, State regulations, voluntary actions under voluntary programs such as the EPA Methane Challenge and Natural Gas STAR, and a literature search. As a result, the standards proposed in this action for NSPS OOOOb, the presumptive standards proposed for EG OOOOc, and the proposed revisions to NSPS OOOOa reflect emission reduction technologies and methods that many owners and operators in the oil and natural gas industry have employed for years, either voluntarily or due to State or other requirements. We note that the level of control in these actions may differ in some respects from our proposed standards. For instance, some state requirements are directed at VOC reduction only while we are proposing standards for reducing both VOC and methane emissions. Some sources are achieving greater methane and/or VOC emission reduction either voluntarily or as required by their states (e.g., 98 percent reduction of), as compared to our proposed standards. Nevertheless, the industry's expansion over these years with the use of these technologies supports the conclusion that the costs of these controls (and other controls of comparable cost) are neither "excessive" nor "more than the industry can bear," and instead are indicative that these control measures are cost effective. The EPA provides the cost effectiveness estimates for reducing VOC and methane emissions for various control options considered in this proposed action. The cost effectiveness values for controls that we consider to be reasonable in this action range from $2,500/ton to $5,800/ton of VOC reduction. 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 based on the Agency's long history of regulating VOC emissions from a wide range of industries. With respect to methane, based on our estimates, the cost effectiveness values for controls that we have identified as BSER in this proposal range $700/ton to $2,100/ton of methane reduction. Unlike VOC, the EPA does not have a long regulatory history to draw upon in assessing the cost effectiveness of controlling methane. The 2016 NSPS OOOOa was the first national standard for reducing methane emissions. However, as explained above, the standards proposed in this action for NSPS OOOOb, EG OOOOc (presumptive standards), as well as the revisions to NSPS OOOOa, reflect emission reduction technologies and methods that many owners and operators in the oil and natural gas industry have employed for years, either voluntarily or due to State or other requirements. We looked but were unable to locate cost analyses or other information relied upon by States when setting standards based on the same technologies and methods that we have identified in this proposal as BSER. We therefore estimated cost effectiveness of the proposed control options based on available information, including various studies, information submitted in previous rulemakings from the affected industry, and information provided by small businesses. The estimated cost-effectiveness values range from $700/ton to $2,100/ton of methane reduction, which, for the reason stated above, we consider to reasonably reflect what is cost effective for reducing methane emissions. 
       In addition to evaluating the total cost-effectiveness of a control option, the EPA also considers the incremental costs of going from one reduction level to a higher reduction level when determining BSER. 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. The incremental cost of control provides insight into how much it costs to achieve the next increment of emission reductions going from one stringency level to the next, more stringent level, and thus is an appropriate tool for distinguishing among the effects of different stringency levels. The EPA generally finds the incremental cost-effectiveness to be reasonable if it is within the range the Agency considers reasonable for total-cost effectiveness. The EPA solicits comments on the approaches described above for evaluating cost effectiveness for emissions reductions of VOC and methane from the oil and natural gas sector in this proposed action. 
      In considering control costs, the EPA takes into account any expected revenues from the sale of natural gas product that would be realized as a result of avoided emissions. Although no D.C. Circuit case addresses how to account for revenue generated from the application of pollution control, or product saved as a result of control, it is logical and a reasonable interpretation of the statute that any expected revenues from the sale of recovered product due to implementation of a control may be considered when determining the overall costs of implementation of the control technology. Clearly, such a sale would offset regulatory costs and so must be included to accurately assess the costs 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. Our cost analysis then applies the monetary value of the saved natural gas as an offset to the control cost. 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. 
      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. 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 for 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.
       The EPA evaluated incremental capital cost 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 15.8 percent increase in capital costs above the $120 million cost of the plant. See 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 Ass'n v. Ruckelshaus, 486 F.2d 375, 387-88 (D.C. Cir. 1973), 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. 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.  
      As shown in the BSER analysis for the proposed standards for NSPS and the presumptive standards in the proposed EG, the associated increase in capital cost is well below the percentage increase previously upheld by the courts, and the annualized cost is less than 1 percent of the annual revenue. Capital expenditure data for relevant NAICS codes were obtained from the U.S. Census 2019 Annual Capital Expenditures Survey.Annual revenue data for relevant NAICS codes were obtained from the U.S. Census 2017 County Business Patterns and Economic Census. For both the capital expenditures and annual revenues, we obtained the Census data and performed the analyses at a sector level. For the capital expenditures analysis, we determined the estimated nationwide capital costs projected to be incurred to comply with the proposed standards, then divided the nationwide capital costs by the new capital expenditures (Census data) for the appropriate NAICS codes to determine the percentage that the nationwide capital costs represent of the capital expenditures. Similarly, for the annual revenues analysis, we determined the estimated nationwide annualize costs projected to be incurred to comply with the proposed standards, then divided the nationwide annualized costs by the annual revenues (Census data) for the appropriate NAICS code(s) to determine the percentage that the nationwide annualized costs represent of annual revenues. The data and analysis supporting the comparison of capital expenditures and annualized costs projected to be incurred under the rule and the sector-level capital expenditures and receipts is presented in the TSD for this action, which is in the public docket.
X. Summary of Proposed Action for NSPS OOOO and 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 2016 NSPS OOOOa, as amended by the 2020 Policy Rule, contained only VOC standards for the production and processing segments, which were further amended by the 2020 Technical Rule. 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. 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: 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. 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 segments. 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 segments, as specified in this section.
	In this action, the EPA is proposing to revise the 2012 NSPS OOOO and 2016 NSPS OOOOa to properly reflect in the CFR those provisions that were reinstated by the CRA resolution. Further, we are also proposing additional amendments to the 2016 NSPS OOOOa to address (1) conflicting VOC standards that we are proposing to rescind from the 2020 Technical Rule, and (2) other modifications made in the 2020 Technical Rule to address other technical and implementation issues. 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. 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 segments, 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 not 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 (2020 TSD), including the costs associated with different monitoring frequencies under the multipollutant approach, 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. 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. Further, while the EPA observed in the 2020 Technical Rule that the $850 per ton of methane reduced is "greater than [$738/ton,] the highest value for methane that the EPA determined to be reasonable in the 2016 NSPS subpart OOOOa," the EPA did not conclude 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 methane cost-effectiveness value from the 2016 NSPS OOOOa, a modest difference that is well within the cost that the EPA concludes to be reasonable in section IX of this notice. Also, as explained in section XI.A.3, 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. 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.         
      It is our understanding that a majority of low production well sites are owned by small businesses, and we remain concerned about the burden of fugitive emissions monitoring requirements on small businesses. Therefore, we are requesting comment on regulatory alternatives for low production 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 low producing well sites, 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.  
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. 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. 
      Similarly, 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. 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 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. 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. 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 follows:
      Flowback means 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. The term 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.
      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. 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. 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. 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.
      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." 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. 
      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 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. 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. 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.
      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. 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, therefore we continue to believe monthly AVO is an appropriate option for pneumatic pumps subject to the 2016 NSPS OOOOa.
      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, 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 the cost-effective. 
      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"). 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.
      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. 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. 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. 
      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." 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.
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.  
      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 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. 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. 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. 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,the EPA is proposing to apply these streamlined recordkeeping and reporting requirements for methane emissions from sources subject to NSPS OOOOa.
      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:
 Revise 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.
 Remove 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.
 Remove 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.
 Require records of the date of first attempt at repair and date of successful repair.
 Revise 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.
 Remove requirement to report the name or ID of operator performing the monitoring survey.
 Remove requirement to report the number and type of difficult-to-monitor and unsafe-to-monitor components that are monitored during each monitoring survey.
 Remove requirement to report the ambient temperature, sky conditions, and maximum wind speed.
 Remove requirement to report the date of successful repair.
 Remove 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 emerging 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. 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. 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. 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. 
      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 emerging 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 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.  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 40 CFR 60.5399a.  
      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 "CPIN/CPIPD." 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 OOOOby 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 incorporates 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. 
      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 at transmission and storage segments 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), 60.5420a(b)(4)(i), and 60.5420a(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 60.5412a(a) and (c) 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 60.5412a(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 60.5412a(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, but did not do so in that rulemaking. 
 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), 60.5415a(b)(4), 60.5416a(d), 60.5420a(b), 60.5420a(b)(13), and introductory text in 60.5411a and 60.5416a, to remove language associated with the administrative stay we issued under 40 CFR 60.307(d)(7)(B) in "Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources; Grant of Reconsideration and Partial Stay" (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 in the public docket.
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. 
1. Emerging Technologies
	Since the 2016 NSPS OOOOa, significant strides have occurred in developing and deploying methane detection technologies that can detect fugitive emissions in a potentially faster and more cost-effective manner than traditional techniques such as OGI and EPA Method 21. The EPA has continued following the development of these technologies and their applications through various public programs, such as the DOE ARPA-E programs, which have focused on the development of cost-effective tools to locate and measure methane emissions. Additionally, the EPA has continued discussions with stakeholders, including academic researchers and private industry, as they develop and evaluate novel tools for the detection and quantification of methane emissions in the oil and gas sector. As noted in section VII.B, the EPA also held a two-day workshop in August 2021 to hear perspectives on these new technologies. Some of the promising technologies now emerging include, but are not limited to, fixed-base and open path sensor networks, unmanned aircraft systems (UAS) equipped with methane detection equipment, the use of high-end instruments for mobile measurements on the ground and in the air, and satellite observations with advanced optical techniques.
      As the EPA learned during the Methane Detection Technology Workshop, industry, researchers, and environmental NGOs have utilized alternative systems to quickly identify large emission sources and target ground based OGI surveys. State and local governments, industry, researchers, and environmental groups have been utilizing advanced technologies to better understand the detection of, source of, and factors that lead to large emission events. Owners and operators have also used these innovative technologies to supplement existing fugitive emissions programs and to identify unexpected emissions events (e.g., emissions from controlled storage vessels) in order to make repairs as quickly as possible. 
      While most of these emerging technologies are not sensitive enough to pin-point the exact same emission sources as the current fugitive emission detection programs, many can more quickly detect the largest emissions sources (e.g., malfunctions and undersized or non-performing major equipment), and they can also find emissions that may be missed by fugitive emission surveys (e.g., component-level leaks on valves, connectors, and meters). The EPA is seeking comment on how to evaluate and design a requirement for owners and operators to investigate and remediate large emission events (commonly known as "super-emitters"), both by looking for these emissions using emerging technologies and in response to credible information presented by third parties who are using these technologies, in addition to (or as an alternative to) the routine fugitive emission surveys proposed in this rule. 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 BSER identified in this proposal. Moreover, the EPA understands the stochastic nature, distribution, and frequency of these large emission events across sites and over time is uncertain, and that these events occur sporadically at an individual site in ways that may take longer to detect or might not be detected through a periodic fugitive emissions survey. Integrating advanced emission detection technologies into this rule  -  whether deployed by owner-operators themselves or by third parties  -  could be a valuable way to reduce fugitive emissions more cost-effectively and rapidly detect and remedy "super-emitting" events that make an outsize contribution to overall emissions from this source category.
      We envision a program for finding large emission events that consists of a requirement that, if emissions are detected above a defined threshold by the owner-operator, a federal or state agency, or any 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. To operationalize such a requirement, the EPA is also 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 owners or operators or third parties to use to identify large emissions events that would need to be investigated more expeditiously than the traditional repair timeline for ground based OGI surveys. 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. 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 them to identify emission events from an individual site. The EPA believes that any emissions visible by satellites should qualify as large emission events. However, should the threshold for what defines a large emission event be lower than what is visible by satellite? 
      In addition, in order to make this approach viable, the EPA would need to define milestones by which an owner or operator must complete certain actions (e.g., when the investigation must begin, and when repairs must be complete). We seek comment on appropriate timelines for these milestones. 
      In addition to the requirements for owners and operators to identify and mitigate large emission events, the EPA would also need to determine how to integrate third-party information so that a single program for tackling large emission events is applicable. First, the EPA would need to define guidelines that would make any third-party data to be used credible or actionable. 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 third-party 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. 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 third-party should notify the owner or operator, as well as how the delegated authority should be made aware of such notification. Further, the EPA is soliciting comment on whether additional information should be required as part of the fugitive emissions monitoring plan that would specify what steps the owner or operator would take when notified by a third-party of large emission events, and if so, what elements should be required in the plan. These elements could include the specific steps the company would take to investigate the notification, 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 prevent ongoing and future chronic or intermittent large emissions from that source. While the EPA may not need to approve the specific parts of the plan for responding to third party notifications, failure to take the actions specified by the owner or operator could be considered noncompliance. Finally, we are soliciting comment on whether the EPA should develop a model plan for responding to third party notifications that companies could adopt instead of developing company- or site-specific plans, including what elements should be included in that model plan.
	In addition to seeking comment on how emerging technologies can be used to identify large emissions events as a layer added to fugitive emission surveys, the EPA is soliciting comment on how to establish an alternative screening work practice using emerging technologies in lieu of ground based OGI fugitive emission surveys or with these OGI surveys at a lesser frequency. There are many advantages to these emerging technologies over technologies currently used for fugitive emissions detection (i.e., OGI and EPA Method 21 technologies). For instance, these emerging technologies have the potential to take the matters requiring judgment out of leak detection, thus making surveys less subjective. The EPA seeks comment on how to evaluate the analytics behind the monitored data, balancing CBI with public transparency. Many of these technologies can survey broader areas than can be effectively surveyed with field personnel, drastically reducing the driving time from site to site, which could have potential cost and safety benefits. Additionally, the broader area coverage could allow for more frequent or even continuous monitoring (e.g., sensor networks), which could allow for the identification and mitigation of large volume methane emissions sooner than OGI or EPA Method 21 surveys alone. As the bulk of emissions in this sector are coming from large fugitive emission events and there are cost-effective methane detection technologies that can identify these events more quickly, the EPA is seeking comment on how we could best implement an alternative screening program using these emerging technologies to supplement or replace the ground-based fugitive emission program at each individual site in this sector. 
      In order to evaluate such an approach, the EPA is seeking comment on how to develop this alternative screening program. One such approach would be to set a minimum detection threshold for the emerging technology and set a frequency at which screening with the emerging technology must occur. To implement this approach, we would need information on what the minimum detection threshold and the screening frequency should be, and data to support the threshold and frequency. Because this screening approach is meant to replace, in part or in whole, the current work practice of ground based OGI fugitive emissions surveys, we believe that this threshold should be lower than the threshold mentioned above for the large emissions events (i.e., 100 kg/hr from an individual site) and that it should be low enough to be able to identify fugitive emissions at the equipment level (e.g., separator or storage vessel). Various studies have presented data on the detection capabilities of these screening technologies, and based on this information, the EPA believes setting a minimum detection threshold of 10 kg/hr methane might be appropriate for use in determining what technologies and in what deployment platforms (e.g., fixed, ground and aerial) are appropriate for a potential screening alternative within the NSPS OOOOb and EG OOOOc. The EPA solicits comment on the use of this 10 kg/hr minimum detection threshold or if another threshold is more appropriate, and data to support another threshold. The EPA is also considering a scenario where the frequency of the screening would be based on the sensitivity of the technology and its application. As such, the EPA solicits comment on how to develop this matrix approach and how to determine the appropriate detection thresholds and corresponding screening frequencies. For example, should the EPA model emission reductions based on different thresholds and monitoring frequencies and then compare it to the proposed OGI survey requirements; and if so, how should the model inputs be developed? The EPA also seeks data and comment on basin-specific emission distributions identified through measurements.
      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. 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. Additionally, we are seeking comment on how OGI surveys can be deployed to respond to detected large emissions, what frequency OGI surveys should occur at sites that implement an alternative screening program, whether this frequency should vary, and what factors should be used in determining the frequency. The EPA recognizes that component-level fugitive emissions may still be present at these sites and believes it is appropriate to identify and repair those emissions, but we believe it is important to incentivize finding and fixing large emissions faster by reducing the frequency of these ground-level OGI surveys.
	The EPA is seeking information that would allow us to evaluate the costs and emission reductions achieved through an alternative screening program. Therefore, the EPA is seeking information on the cost of screening surveys using different types of emerging 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 cost-sharing such opportunities. We also solicit comment on whether these technologies and cost-sharing opportunities would allow for cost-effective monitoring at all well sites. Further, we seek comment on the current and expected availability of these emerging 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 an alternative work practice.
	Although we have focused this discussion on emerging technologies, the EPA is also soliciting comment on whether there are ways to utilize existing technologies to screen for large emission events. For example, could gauges or meters be utilized to identify potential large losses between the wellhead and the custody meter assembly.
	The 2016 NSPS OOOOa includes provisions for the application of AMEL (see preamble section X.B.5), where anyone can apply to use these innovative technologies in place of the required fugitive emissions monitoring and repair work practice, provided the requestor demonstrates that the alternative will result in equivalent or better emission reductions than the required work practice. While the EPA is not proposing to remove the AMEL provisions, we think that it is preferrable to implement this alternative screening approach without the need for an AMEL. However, in the absence of formal test methods for these technologies, we are soliciting comment on how the Agency can best implement the screening procedures for the emerging technologies and how we can structure this approach in a manner that is performance-based, such that compliance is based on data quality metrics, transparent reporting and recordkeeping, and data auditability through the rule itself. Additionally, the EPA is seeking information from stakeholders on what work practices or protocols have been employed for these emerging technologies to aid in the development of work practices for this potential screening alternative. 
      However, we do not have enough information at this time to determine how a fugitive emissions screening work practice using emerging 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. Information provided through this solicitation may be used to propose a screening alternative or to reevaluate BSER through a supplemental proposal.
 2. 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 controlled because of NSPS OOOOa but rather by state requirements. 
 	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 as "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 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 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 utilize 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 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 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. 
 3. 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 subpart 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. We are further proposing that monitoring must begin within 90 days of startup of production (or startup of production after modification). 
	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, 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 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. For each natural gas-driving 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. 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 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. 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, rather than conclusory statements, to support commenters' positions. The EPA also requests comment on whether there are additional production and processing equipment 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, and associated gas venting at a well site. If such equipment 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 monitoring where site-level baseline methane emissions are below 5 tpy, the EPA is also soliciting comment on whether a different approach to fugitive emissions surveys, such as the use of emerging technologies as discussed in section XI.A.1 would be appropriate in place of the ground based OGI surveys. As discussed there, the use of emerging technologies would allow for a potentially more cost-effective approach to identifying and mitigating large emission events should they occur.
 TABLE 13. PROPOSED WELL SITE MONITORING FREQUENCIES BASED ON SITE-LEVEL BASELINE METHANE EMISSIONS
                Site-level Baseline Methane Emissions Threshold
                            OGI Monitoring Frequency
                              >0 and <5 tpy
                             No monitoring required
                              >=5 and <15 tpy
                                   Semiannual
                                   >=15 tpy
                                   Quarterly
       
       Where quarterly monitoring is proposed, subsequent quarterly monitoring would occur at least 60 days apart. Where semiannual monitoring is 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 ℉ 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. Today, 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.
      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 technical support document 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, HAPs, and methane from industrial environments. 
      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. 
       Once fugitive emissions are detected during the OGI survey, we are proposing that 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 repair requirements are the same as those in the current NSPS OOOOa (as amended in the 2020 Technical Rule for VOC). 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. 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 5 tpy threshold to require 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.K. 
       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 are a work practice, therefore they would not require the installation of controls or the retrofit of equipment, which can generally be an additional factor for consideration 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 and are owned or operated by small businesses, 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.
	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 in the absence of an alternative utilizing emerging technologies. 
 4. 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. 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. 
 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.3, 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 ℉ 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 in the absence of an alternative approach utilizing emerging technologies. 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. 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, especially for older existing sites where the conditions at the station would result in minimal methane emissions, but where equipment could be older and more prone to leaks and malfunctions. 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 necessitate similar subcategorization. Should information provided through this solicitation support subcategorization for the NSPS and/or the EG, including possible exemptions from monitoring if a subcategory is shown to have such low fugitive emissions that it is not cost effective to control, the EPA may consider subcategorization through a supplemental proposal.
      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." 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. 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.3, the EPA is soliciting comment on whether repairs at compressor stations should be made based on severity of the emissions found. Please refer to section XI.A.3 for additional details on this solicitation for comment.
B. Storage Vessels
1. NSPS OOOOb
      The current NSPS in 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 both continuous bleed natural gas driven pneumatic controllers that are located at an onshore natural gas processing plants and those that are not located at an onshore natural gas processing plant. For the former, the current NSPS requires a zero natural gas bleed rate. For the latter, 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 natural gas driven pneumatic controllers at any location. 
      Based on our analysis, which is summarized in section XII.C.1, the EPA is proposing to update the current NSPS as follows. First, the EPA is proposing to two separate types of affected facilities for pneumatic controllers which include each single continuous bleed natural gas driven pneumatic controller at a site and the collection of all natural gas driven intermittent vent controllers at a site. The EPA proposes to include intermittent pneumatic controllers as an affected facility, because intermittent devices represent a large majority of the overall population of pneumatic controllers and of emissions from these sources, and are prone to malfunctions that lead to significant discharges of methane and can be readily detected and remedied through regular fugitive emissions monitoring. Second, because the options available for reducing or eliminating emissions from pneumatic controllers depend significantly on the availability of onsite power, the EPA has identified two subcategories for pneumatic controllers located in the production, including gathering and boosting, and transmission and storage segments: (1) natural gas driven pneumatic controllers at sites with onsite power available (subcategory 1); and (2) natural gas driven pneumatic controllers at sites where onsite power is not available (subcategory 2). Onsite power can mean access to the electric grid or to power generated by an onsite power generation station capable of providing electricity to the entire site; installation of electric services is not required for this purpose.  For both subcategories, the EPA proposes that the definitions of affected facility remain the same as described above and in section XII.C.1 in more detail. 
      For subcategory 1, we are proposing a requirement that all controllers (continuous bleed and intermittent vent) must have a VOC and methane emission rate of zero, which can be achieved by using non-emitting pneumatic controllers such as air-driven pneumatic controllers, electric controllers, and self-contained pneumatic controllers. For each individual continuous bleed pneumatic controller in subcategory 2, the EPA is proposing a standard of a natural gas bleed rate not to exceed 6 scfh. Additionally, for each single intermittent natural gas-driven pneumatic controller in subcategory 2, we propose to require fugitive monitoring to verify proper actuation and that venting does not occur during idle times. We propose to define an intermittent natural gas-driven pneumatic controller to mean a pneumatic controller that is not designed to have a continuous bleed rate but is designed to only release natural gas to the atmosphere as part of the actuation cycle. Please refer to sections XI.A and XII.A of this preamble which summarize and detail the proposed fugitive monitoring and repair provisions.
       For natural gas processing plants, the EPA is proposing to define the affected facility as the collection of all gas-driven pneumatic controllers, including intermittent natural gas-driven pneumatic controllers. For the collection of pneumatic controllers located at onshore natural gas processing plants, the EPA proposes to retain the current standards for GHGs (in the form of limitations on methane) and VOC, which is a zero natural gas bleed rate (i.e., they are operated by means other than natural gas, such as being driven by compressed instrument air). 
2. EG OOOOc	
      In this action, the EPA is proposing to subcategorize designated facilities (existing sources) in the same manner as the definitions described above for pneumatic controller affected facilities for subcategory 1, subcategory 2, and natural gas processing, as proposed for new sources. 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 in these subcategories that is the same as what 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, 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, 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; (3) follow the BMPs during each liquids unloading and maintain records demonstrating they were followed; (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 the specific practices that must be included, it would specify 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 demonstrate that they did not use non-venting methods and were not subject to NSPS OOOOb. The requirements for wells that use methods that vent would be the same as described above under Option 1. 
      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. 
	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 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 results 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. 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.
E. Reciprocating Compressors
1. NSPS OOOOb
      The current NSPS in 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. 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.K 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 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. 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.K 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.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 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. The current NSPS for a natural gas driven diaphragm pneumatic pump at an onshore natural gas processing plant is zero natural gas emissions, based on natural gas as a surrogate for VOC and GHG, the two regulated pollutants. 
      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. The EPA is proposing to retain the current alternative of routing emissions to a process, as such control would achieve at least 95 percent control but may not always be feasible. Thus, if a control device or the ability to route to a process is not available onsite, the pneumatic pump affected facility would not be subject to the 95 percent control requirement. Moreover, there may be a control device or process available onsite, but it may not be capable of achieving a 95 percent reduction. In those cases, we propose to retain the current standard to require the owner or operator to route the emissions to such existing control device even it if achieves a level of emissions reduction less than 95 percent. In those instances, the owner or operator must 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. 
      We are also proposing to expand the applicability of the standard currently in NSPS OOOOa by including all natural gas driven diaphragm pumps in the production segment (i.e., including the gathering and boosting segment) and the transmission and storage segment as affected facilities. We are proposing the same standards for these segments as those described above for natural gas driven diaphragm pumps at well sites because the BSER is the same.     
       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 as our analysis discussed in section XII.G.1 demonstrates this standard remains the BSER.
2. EG OOOOc
       The EPA is proposing EG that include a presumptive methane standard that is 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. 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. Based on the analysis in section XII.G.2, the BSER for reducing GHGs from new and existing natural gas driven diaphragm pneumatic pumps are the same.
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 incorporates 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, 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. As explained in X.I, 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.  
       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 well sites and compressor stations. The proposed definition of "first attempt at repair" is "an action taken for the purpose of stopping or reducing fugitive emissions or equipment leaks to the atmosphere. First attempts at repair include, but are not limited to, the following practices where practicable and appropriate: tightening bonnet bolts; replacing bonnet bolts; tightening packing gland nuts; or injecting lubricant into lubricated packing." The proposed definition for "repaired" is "fugitive emissions components or equipment are adjusted, replaced, or otherwise altered, in order to eliminate fugitive emissions or equipment leaks as defined in this subpart and resurveyed to verify that emissions from the fugitive emissions components or equipment are below the applicable leak definition." Repairs can include replacement with low-emissions ("low-e") valves or valve packing, where commercially available, as well as drill-and-tap with a low-e injectable. These low-e equipment meet the specifications of API 622 or 624. Generally, a low-e valve or valve packing product will include a manufacturer written warranty that it will not emit fugitive emissions at a concentration greater than 100 ppm within the first five years. Further, we are proposing to incorporate the delay of repair provisions that are in 40 CFR 60.482-9a of NSPS VVa (and incorporated into NSPS OOOOa). These provisions would allow the delay of repairs where it is technically infeasible to complete repairs within 15 days without a process unit shutdown and require repair completion before the end of the next process unit shutdown. 
       Fourth, we are proposing to retain the current requirements in NSPS OOOOa for open-ended valves or lines, closed vent systems and equipment designated with no detectable emissions, and PRDs. For open-ended valves or lines, we propose to retain the requirements in 40 CFR 60.482-6a of NSPS VVa. Specifically, we are proposing that each open-ended valve or line in a new or existing process unit must be equipped with a closure device (i.e., cap, blind flange, plug, or a second valve) that seals the open end at all times except during operations requiring process fluid flow through the open-ended valve or line. The EPA is soliciting comment on requiring OGI monitoring (or EPA Method 21 monitoring for those opting for that alternative) on these open-ended valves or lines equipped with closure devices to ensure no emissions are going to the atmosphere. Specifically, the EPA is soliciting information that would aid in determining what additional costs would be incurred from either OGI or EPA Method 21 monitoring and repair of leaking open-ended valves or lines, and information on leak rates and concentrations of emissions, where monitoring has been performed.
      While the EPA is proposing to retain the no detectable emission requirement in NSPS OOOOa for closed vent systems and equipment designated as having no detectable emissions (e.g., valves or PRDs), the EPA is also soliciting comment on whether bimonthly OGI monitoring according to the proposed Appendix K is appropriate to demonstrate compliance with this requirement. The current NSPS requires the closed vent systems and the other equipment described above to operate with no detectable emissions, as demonstrated by an instrument reading of less than 500 ppm above background with EPA Method 21. On December 22, 2008, the EPA issued a final rule titled, "Alternative Work Practice to Detect Leaks from Equipment" (AWP). In that final rule, the EPA did not permit the use of OGI for this equipment, stating, "the AWP is not appropriate for monitoring closed vent system, leakless equipment, or equipment designated as non-leaking. While the AWP will identify leaks with larger mass emission rates, tests conducted with both the AWP and the current work practice indicate the AWP, at this time, does not identify very small leaks and may not be able to identify if non-leaking/leakless equipment are truly nonleaking because the detection sensitivity of the optical gas imaging instrument is not sufficient." 73 FR 78204. The EPA is soliciting information that would support the use of OGI for closed vent systems and equipment designated with no detectable emissions at new and existing process units, including comment on applying the proposed bimonthly OGI monitoring requirement on this equipment in place of the NSPS VVa annual EPA Method 21 monitoring. 
       Finally, the EPA is proposing to retain the emission standards for PRDs found in 40 CFR 60.482-4a of NSPS VVa. This provision requires that PRDs be operated with no detectable emissions, except during pressure releases at new and existing process units. As stated above, the EPA is soliciting comment on the use of OGI to demonstrate that PRDs are meeting this operational emission standard. 
2. EG OOOOc
       The EPA is proposing EG that include a presumptive methane standard that is the same as described above for the NSPS OOOOb for equipment leaks at existing onshore natural gas processing plants. Based on the analysis in section XII.H.2, the BSER for reducing GHGs from equipment leaks at new and existing onshore natural gas processing plants are the same.  
I. Well Completions  
      Based on our understanding that there are no advances in technologies or practices, which is summarized in section XII.I, the EPA is proposing to retain the reduced emission completion standards as it continues to reflect the BSER for reducing methane and VOC emissions from well completions at hydraulically fractured (or refractured) wells. These proposed standards are the same as those for natural gas and oil wells regulated in the 2012 NSPS OOOO and 2016 NSPS OOOOa, as amended in the 2020 Technical Rule for VOC and proposed in section X.B.1 for methane. Because of the nature of well completions, any completion (or recompletion) is considered a new or modified well affected facility, therefore, the EPA does not believe there are existing well affected facilities to which a EG OOOOc presumptive standard for well completions would apply.
J. Sweetening Units
	Based on our understanding that no advances in technologies or practices are available to reduce SO2 emissions from sweetening units, as described in section XIII.J, the EPA is proposing to retain the standards as it continues to reflect the BSER. These proposed standards are the same as those for sweetening units regulated in the 2016 NSPS OOOOa, and as amended in the 2020 Technical Rule. 
K. Centralized Production Facilities
	The EPA is also proposing a new definition for "centralized production facility," which 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." The EPA is proposing this definition to (1) specify how the fugitive emissions requirement apply to centralized production facilities, (2) specify how exemptions related to 40 CFR part 60, subparts K, Ka, or Kb ("NSPS Kb) may apply, and (3) specify what standards would apply to reciprocating and centrifugal compressors located at these facilities. 
	First, the EPA is proposing to specify how the fugitive emission requirements apply to centralized production facilities. 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. The inclusion of centralized tank batteries in the definition of well site was used to clarify the boundary of a well site for purposes of the fugitive emissions requirements. Further, in the RTC for the 2016 NSPS OOOOa we stated, "[o]ur intent is to limit the oil and gas production segment up to the point of custody transfer to an oil and natural gas mainline pipeline (including transmission pipelines) or a natural gas processing plant. Therefore, the collection of fugitive emissions components within this boundary are a part of the well site." The EPA continues to define these facilities as a type of well site but is proposing a separate definition to provide further clarity, especially as it relates to when these facilities are modified, and thus become subject to the fugitive emissions requirements in NSPS OOOOb. The EPA has determined it is appropriate to rename this site as a centralized production facility and to provide the specific definition above to avoid confusion with the storage vessel affected facility, of which applicability is determined for a tank battery, and to better specify the facility name based on the basic function the site performs (i.e., production operations).
	Second, the EPA has received questions related to whether NSPS Kb would apply to the storage vessels at centralized production facilities. There is an exemption in NSPS Kb for storage vessels in the producing operations that are below a specific size. Specifically, 40 CFR 60.110(b)(4) exempts "vessels with a design capacity less than or equal to 1,589.874 m[3] used for petroleum or condensate stored, processed, or treated prior to custody transfer." This exemption is a revision of an exemption originally promulgated in 40 CFR part 60, subpart K ("NSPS K"). NSPS K "does not apply to storage vessels for the crude petroleum or condensate stored, processed, and/or treated at a drilling and production facility prior to custody transfer." 40 CFR 60.110(b). In that final rule the EPA explained that, "[t]he storage of crude oil and condensate at producing fields is specifically exempted from the standard." 39 FR 9312. While "producing fields" were not explicitly defined, NSPS K defined the terms "custody transfer" and "drilling and production facility". For purposes of NSPS K, custody transfer means "the transfer of produced crude petroleum and/or condensate, after processing and/or treating in the producing operations, from storage tanks or automatic transfer facilities to pipelines or any other forms of transportation." 40 CFR 60.111(g). Drilling and production facility means "all drilling and servicing equipment, wells, flow lines, separators, equipment, gathering lines, and auxiliary nontransportation-related equipment used in the production of crude petroleum but does not include natural gasoline plants." 40 CFR 60.111(h). The definition of "custody transfer" was later also incorporated into 40 CFR part 60, subpart Ka ("NSPS Ka"), NSPS Kb, and 40 CFR part 63, subpart HH (National Emission Standards for Hazardous Air Pollutants from Oil and Natural Gas Production Facilities).
	Instead of a categorical exemption for storage vessels located at drilling and production facilities, NSPS Ka, and subsequently NSPS Kb, adopted threshold-based exemptions that are based on the capacity of an individual storage vessel used to store petroleum (crude oil) or condensate prior to custody transfer. In NSPS Ka, the EPA stated "[t]his exemption applies to storage between the time that the petroleum liquid is removed from the ground and the time that custody of the petroleum liquid is transferred from the well or producing operations to the transportation operations" 45 FR 23377. In NSPS Kb, the EPA further stated that "[t]he promulgated standards for petroleum liquid storage vessels specifically exempted vessels with a capacity less than 420,000 gallons and storing petroleum (crude oil) and condensate prior to custody transfer (production vessels). The emission controls that are applicable to the storage vessels included in the standards being proposed are not applicable to production vessels." 49 FR 29701.
 	The EPA continues to find it inappropriate to use the controls required by NSPS K, Ka, and Kb on storage vessels located in the production segment, especially where flash emissions are prevalent. Specifically, the NSPS K, Ka, and Kb control requirements include provisions allowing the use of floating roofs to reduce emissions from storage tanks. Floating roofs are not designed to store liquid (or gases) under pressure. Pressurized liquid sent to a storage vessel from a well or separator or other process that operates above atmospheric pressure may contain dissolved gases. These gases will be released or "flash" from the liquid as the fluid comes to equilibrium with atmospheric pressure within the storage vessel. The flash gas will either be released from gaps in the seal system or from "rim vents" on the floating roof. The rim vent may be an open tube or may be fitted with a low-pressure relief valve, but it is specifically designed to allow any gas entrained or dissolved in the storage liquid to be released above the floating roof. That is, floating roofs are not designed to prevent the release of flash gas, they are only designed to limit the volatilization of a liquid that occurs when the storage liquid is directly exposed with unsaturated air. Since a significant portion of emissions from storage vessels at well sites or centralized production facilities are from flash gas, floating roofs are much less effective at reducing storage vessel emissions than venting these emissions through a CVS to a control or recovery device.
	Further, it is the EPA's understanding that these centralized production facilities carry out the same operations that would be conducted at the individual well sites. Therefore, the EPA is proposing a definition of "centralized production facility" that clearly specifies these facilities are located within the producing operations. Therefore, if all other conditions are met, storage vessels at these centralized facilities would meet the exemption criteria for NSPS Kb. 
	Finally, the EPA is now proposing to define centralized production facilities separately from well sites because the number and size of equipment, particularly reciprocating and centrifugal compressors, is larger than standalone well sites which would not be included in the proposed definition of "centralized production facilities" above. In the 2016 NSPS OOOOa, the EPA exempted reciprocating and centrifugal compressors located at well sites from the applicable compressor standards. 
      Reciprocating compressors that are located at well sites are not affected facilities under the 2016 NSPS OOOOa. The EPA previously excluded them because we found the cost of control to be unreasonable. 81 FR 35878. However, as mentioned above, the EPA believes the definition of "well site" in NSPS OOOOa may cause confusion regarding whether reciprocating compressors located at centralized production facilities are also exempt from the standards. In our current analysis, described in section XII.E, we find it is appropriate to apply the same emission factors to reciprocating compressors located at centralized production facilities as those used for reciprocating compressors at gathering and boosting compressor stations. Given the results of that analysis, the EPA is proposing to apply the proposed NSPS OOOOb and presumptive standards in EG OOOOc to reciprocating compressors located at centralized production facilities. The new definition above is intended to apply the results of the EPA's analysis. We believe that this new definition is necessary in the context of reciprocating compressors to distinguish between these compressors at centralized production facilities where the EPA has determined that the standard should apply, and these compressors at standalone well sites where the EPA has determined that the standard should not apply. See section XII.E for more details of those proposed standards.
      Similarly, 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. In our current analysis, described in section XII.F, we find it is appropriate to apply the same emission factors to wet seal centrifugal compressors located at centralized production facilities as those used for these same compressors at gathering and boosting compressor stations. Given the results of that analysis, the EPA is proposing to apply the proposed NSPS OOOOb and presumptive standards in EG OOOOc to wet seal centrifugal compressors located at centralized production facilities. See section XII.F for more details of those proposed standards.     
L. Recordkeeping and Reporting 
	The EPA is proposing to require electronic reporting of performance test reports, annual reports, and semiannual reports through the Compliance and Emissions Data Reporting Interface (CEDRI). (CEDRI can be accessed through the EPA's Central Data Exchange (CDX) at https://cdx.epa.gov/.) A description of the electronic data submission process is provided in the memorandum Electronic Reporting Requirements for New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants (NESHAP) Rules, available in the docket for this action. Performance test results collected using test methods that are supported by the EPA's Electronic Reporting Tool (ERT) as listed on the ERT website at the time of the test would be required to be submitted in the format generated through the use of the ERT or an electronic file consistent with the xml schema on the ERT website, and other performance test results be submitted in portable document format (PDF) using the attachment module of the ERT. For semiannual and annual reports, the owner or operator would be required to use the appropriate spreadsheet template to submit information to CEDRI. 
	The EPA is also proposing to allow owners and operators the ability to seek extensions for submitting electronic reports for circumstances beyond the control of the facility, i.e., for a possible outage in CDX or CEDRI or for a force majeure event, in the time just prior to a report's due date. The EPA is providing these potential extensions to protect owners and operators from noncompliance in cases where they cannot successfully submit a report by the reporting deadline for reasons outside of their control. The decision to accept the claim of needing additional time to report is within the discretion of the Administrator.
      Electronic reporting is required in the amended 2016 NSPS OOOOa, and the EPA believes that the electronic submittal of these reports in the proposed NSPS OOOOb will increase the usefulness of the data contained in those reports, is in keeping with current trends in data availability, will further assist in the protection of public health and the environment, and will ultimately result in less burden on the regulated community. Electronic reporting can also eliminate paper-based, manual processes, thereby saving time and resources, simplifying data entry, eliminating redundancies, minimizing data reporting errors, and providing data quickly and accurately to the affected facilities, air agencies, the EPA, and the public. Moreover, electronic reporting is consistent with the EPA's plan to implement EO 13563 and is in keeping with the EPA's agency-wide policy developed in response to the White House's Digital Government Strategy.	
 	In addition to the annual and semiannual reporting requirement, the EPA is soliciting comment on what elements, if any, are appropriate for more frequent reporting, and what mechanism would be appropriate for the collection and public dissemination of this information. For example, it may be appropriate to make information related to large emission events public in a timelier manner than the annual reporting period. Therefore, the EPA is soliciting comment on the appropriate mechanism to use for this type of report, including how the data would be reported, who would manage that reporting system, the frequency at which the data should be reported, the potential benefits of more frequent reporting for reducing emissions, the associated burden with this type of reporting and ways to mitigate that burden, and other considerations that should be taken into account. 
M. Prevention of Significant Deterioration and Title V Permitting
 	The pollutant we are proposing to regulate is GHGs, not methane as a separately regulated pollutant. As explained in section XV of this preamble, we are proposing to add provisions to NSPS OOOOb and EG OOOOc, analogous to what was included in the 2016 NSPS OOOOa and other rules regulating GHGs from electric utility generating units, to make clear in the regulatory text that the pollutant regulated by this rule is GHGs. The proposed addition of these and other provisions is intended to address some of the potential implications on the CAA Prevention of Significant Deterioration (PSD) preconstruction permit program and the CAA title V operating permit program. 
XII. Rationale for Proposed NSPS OOOOb and EG OOOOc
      The following sections provide the EPA's BSER analyses and the resulting proposed NSPS to reduce methane and VOC emissions and the resulting proposed EG, which include presumptive standards, to reduce methane emissions from across the Crude Oil and Natural Gas source category. Our general process for evaluating BSER for the emission sources discussed below included: (1) identification of available control measures; (2) evaluation of these measures to determine emission reductions achieved, associated costs, non-air environmental impacts, energy impacts and any limitations to their application; and (3) selection of the control techniques that represent BSER. As discussed in the 2016 NSPS OOOOa, the available control technologies will reduce both methane and VOC emissions at the same time. The revised BSER analysis we have undertaken for the sources addressed in the proposed NSPS OOOOb continues to support this conclusion. CAA Section 111 also requires the consideration of cost in determining BSER. Section IX describes how the EPA evaluates the cost of control for purposes of this rulemaking. Sections XII.A through XII.I provide the BSER analysis and the resulting proposed NSPS and EG for the individual emission sources contemplated in this action. Please note that there are minor differences in some values presented in various documents supporting this action. This is because some calculations have been performed independently (e.g., TSD calculations focused on unit-level cost-effectiveness and RIA calculations focused on national impacts) and include slightly different rounding of intermediate values. Further, for this proposed 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.
A. Proposed Standards for Fugitive Emissions from Well Sites and Compressor Stations
1. NSPS OOOOb
      There are several potential sources of fugitive emissions throughout the Crude Oil and Natural Gas Production source category. Fugitive emissions occur when connection points are not fitted properly or when seals and gaskets start to deteriorate. Changes in pressure and mechanical stresses can also cause components or equipment to emit fugitive emissions. Poor maintenance or operating practices, such as improperly reseated pressure relief valves (PRVs) or worn gaskets and springs on thief hatches on controlled storage vessels are also potential causes of fugitive emissions. Additional sources of fugitive emissions include agitator seals, connectors, pump diaphragms, flanges, instruments, meters, open-ended lines, PRDs such as PRVs, pump seals, valves or controlled liquid storage tanks. 
      The 2021 GHGI estimates methane emissions of 72.2 MMT CO2 Eq. from onshore production in 2019 (the most recent year of estimates). Of this amount, equipment leaks account for around 10 MMT CO2 Eq. In addition, fugitive emissions may be represented in other categories of the GHGI production segment; for example, a portion of fugitive emissions are also expected to be related to emissions from malfunctioning pneumatic devices. Methane emissions from pneumatic devices are estimated to be 45.7 MMT CO2 Eq. within onshore production, according to the 2021 GHGI. According to the 2021 GHGI, the gathering and boosting segment is estimated to emit 40.9 MMT CO2 Eq. Of this amount, equipment leaks are estimated to be 2.4 MMT CO2 Eq. In the 2016 OOOOa Rule, the EPA promulgated standards to control GHGs (in the form of limitations on methane emissions) and VOC emissions from fugitive emissions components located at well sites and compressor stations. These standards required a fugitive emissions monitoring and repair program, where well sites and compressor stations had to be monitored semiannually and quarterly, respectively. 
      As a result of the review of these requirements pursuant to CAA section 111(b)(1)(B), the EPA is proposing to control methane and VOC emissions by requiring semiannual monitoring for well sites with site-level baseline methane emissions greater than or equal to 5 tpy and less than 15 tpy; quarterly monitoring for well sites with site-level baseline methane emissions greater than or equal to 15 tpy; and quarterly monitoring for all compressor stations, which include gathering and boosting, transmission, and storage compressor stations. At well sites, the composition of gas is predominantly methane (approximately 70 percent). Therefore, monitoring for methane emissions would be required before monitoring for VOC emissions. For this reason, we chose to use methane as the threshold for our determination. 
      In addition to the requirements to monitor for fugitive emissions from components based on the proposed definition of an affected facility under the fugitive emissions monitoring requirements of proposed NSPS OOOOb, the EPA is proposing to require use of the fugitive emissions monitoring program to demonstrate that "subcategory 2 natural gas-driven intermittent pneumatic controllers" (i.e., those located at a site without power) are meeting the proposed standard applicable to those affected facilities, which prohibits venting during idle periods. While these intermittent controllers are their own separate affected facilities instead of being part of the collection of  the fugitive emission components affected facilities, we are proposing that they be monitored in conjunction with fugitive components affected facilities located at the same well site or compressor station in accordance with the proposed fugitive emissions standards applicable to that well site or compressor station, as explained in section XII.D.  Accordingly, the cost of monitoring these intermittent controllers is evaluated in this section. As shown in section XII.A.1, this cost does not substantially change the cost of the OGI survey required for fugitive emissions components since monitoring intermittent controllers does not increase the survey time unless they are found to be malfunctioning.
      Previously the BSER analyses for fugitive emissions from well sites in the 2016 NSPS OOOOa and the 2020 Technical Rule were based on "model" plants, without regard to the actual types and number of equipment (and corresponding fugitive emission potential) at individual sites. The EPA developed separate model plants based on production levels for the 2020 Technical Rule, but that effort was based on very limited data and there were considerable comments received on the uncertainty regarding the relationship between the fugitive emissions and production levels. The EPA has now determined that its prior model plant approach cannot adequately account of various factors that affect the level of fugitive emissions. Such factors include the wide variation in the well characteristics, type of oil and gas products and production levels, gas composition, and types of equipment at well sites. Therefore, the EPA has revised the fundamental approach for estimating the baseline emissions from well sites as the foundation for the BSER analysis, where these baseline emissions will be determined for each site using site-specific information. Based on this new approach, described in more detail below, the EPA determined that the BSER for reducing methane and VOC from well sites would be monitoring frequencies based on a well site's baseline methane emissions. The EPA concluded that the model plant approach used in previous analyses for compressor stations is still a sound means to evaluate BSER.
a. Fugitive Emissions from Well Sites
      Oil and natural gas production practices and equipment vary from well site to well site. A well site can serve one well or multiple wells. Some production sites may include only a single wellhead that is extracting oil or natural gas from the ground, while other sites may include multiple wellheads with a number of operations such as production, extraction, recovery, lifting, stabilization, separation and/or treating of petroleum and/or natural gas (including condensate). In addition, the 2016 NSPS OOOOa definition of well site also includes centralized tank batteries to clarify the boundary of a well site for purposes of the fugitive emissions requirements. The equipment to perform these operations (including piping and associated components, compressors, generators, separators, storage vessels, and other equipment) has components that may be sources of fugitive emissions. Therefore, the number of components with the potential for fugitive emissions can vary depending on the number of wells and the number of major production and processing equipment at the site. Another factor that impacts the operations at a well site, and the resulting fugitive emissions potential, is the nature of the oil and natural gas being extracted. This can range from well sites that only extract and handle "dry" natural gas to those that extract and handle heavy oil.
      As noted above, in both the 2016 NSPS OOOOa and subsequent amendments in the 2020 Technical Rule, the EPA relied on a model plant approach to estimate emissions from well sites. Model plants were developed to provide a representation of well sites across the spectrum. Separate production-based model plants using component counts to determine baseline emissions were developed. The basic approach used was to assign a number of specific equipment types for each well site model plant and then to estimate the number of components based on assigned numbers of components per equipment type. Primarily, the well site model plants utilized information from the DrillingInfo HPDI(R) database, the 1996 EPA/GRI Study, EPA's GHG Inventory, and GHGRP subpart W. Fugitive model plants were originally developed for the 2015 NSPS OOOOa proposed rule and evolved over time in response to new information and public comments. More information on the history of the model plant development can be found in the 2015 NSPS Proposal TSD, the 2016 NSPS Final TSD, the 2018 NSPS Proposal TSD, and the 2020 NSPS Final TSD. 
      In this proposal, the EPA is shifting away from using model plants for well sites for the BSER analysis and is instead using an individual site-level emission-calculation approach in order to better characterize and take into account the differences at individual well sites that can lead to a vast range in the magnitude of fugitive emissions, which a model plant cannot do. Provided below is a more detailed explanation of the issues concerning the previous model plant approach, followed by a description of the site-specific baseline emission calculation approach, which is similar to the State of Colorado's LDAR program. 
      In the 2020 Technical Rule, the EPA created separate model plants to represent fugitive emissions from low production well sites (those producing 15 boe or less per day) and non-low production well sites, as it was generally assumed that low producing sites would have fewer major production and processing equipment and thus lower fugitive emissions. This prior estimate of baseline emissions was calculated using model plant site designs with assumed populations of major production and processing equipment and fixed fugitive emissions component counts. While the estimated baseline emissions from the two model plants differ due to the difference in the assumed populations of major production and processing equipment and fixed fugitive emissions component counts, the estimated baseline emissions were intended to represent the baseline emissions for all well sites represented by each model plant. Since that rulemaking, further analysis of existing and new information indicates that there is significant variation in the operations, and types and quantity of equipment at well sites across the U.S., and the EPA has concluded that the previous model plant approach may not be reflective of differences in baseline fugitive emissions from all the different well sites.  Further, the potential for fugitive emissions at any given site is impacted more by the number and type of equipment at the site and maintenance practices, and not by the volume of production. Given these limitations in utilizing model plants to analyze fugitive emission reduction programs at well sites with widely varying configurations, operations, and production levels, we find it appropriate to shift away from using model plants and instead rely on the potential fugitive emissions at the individual site in our BSER analysis and resulting proposed standards. Therefore, this new analysis, which is described below, is conducted on this basis. 
      This site-specific baseline emissions calculation approach is similar to the State of Colorado's LDAR program. The concept is that each site calculates its baseline methane emissions for all the equipment at the site, the number and type of equipment at the well site, the number of fugitive emissions components associated with each piece of equipment, and the site-specific gas composition. The fugitive monitoring frequency would be based on the baseline site-specific methane emissions level calculated based on this information. This calculation is described in detail in section XI.A.3. We believe that this approach will more accurately depict the emissions profile at each individual well site. As a result, the EPA is conducting the BSER analysis based on site-level baseline methane emissions, where the analysis will be performed in increments of 1 tpy of site-level baseline methane emissions as discussed more below.
      During the rulemaking for the 2016 NSPS OOOOa, the EPA analyzed two options for reducing fugitive methane and VOC emissions at well sites: a fugitive emissions monitoring program based on individual component monitoring using EPA Method 21 for detection combined with repairs and a fugitive emissions monitoring program based on the use of OGI detection combined with repairs. Finding that both methods achieve comparable emission reduction but OGI was more cost effective, the EPA ultimately identified semiannual monitoring of well sites using OGI as the BSER. 81 FR 35856. While there are several new fugitive emissions technologies under development, the EPA needs additional information and better understanding of these technologies, and they are therefore not being evaluated as potential BSER at this time. For this analysis for both the NSPS and the EG, we re-evaluated the use of OGI as BSER. In the discussion below, we evaluate OGI control options based on varying the frequency of conducting the survey and fugitive emissions repair threshold (i.e., the visible identification of methane or VOC when an OGI instrument is used). For this analysis, we considered biennial, annual, semiannual, quarterly, and monthly survey frequency for well sites. 
The regulatory concept for the proposed NSPS OOOOb is that the required frequency of fugitive monitoring would be based on total site baseline methane emissions. 
	For the BSER analyses, we selected for evaluation total site-wide methane and VOC emissions increments of 1 tpy of site-level baseline methane emissions ranging from 1 tpy to 50 tpy. For purposes of estimating fugitive emissions and emissions reductions achievable via the OGI-based monitoring program, we assume that 50 percent of the total site emissions are fugitive emissions that can be mitigated through an OGI-based program (the other 50 percent of the site emissions are emissions that are "allowed"). While this could be overstating or understating the percentage of emissions that are fugitive, and that can be mitigated through the fugitive program, the EPA concludes this is a reasonable assumption for this analysis because certain emissions, such as those from a low-bleed natural gas-driven pneumatic controller, will occur as part of normal operations and would not be considered fugitive emissions. The EPA acknowledges that the site-level baseline methane emissions calculated may not account for the presence of large emission events when they occur. However, the EPA has found it inappropriate to apply a factor that assumes every site is experiencing a large emission event annually based on information suggesting that only a small percentage of sites experience these events at any given time.
      In 2015, we evaluated the potential emission reductions from the implementation of an OGI monitoring program where we assigned an emission reduction of 40, 60 and 80 percent to annual, semiannual, and quarterly monitoring survey frequencies, respectively. The EPA re-evaluated the control efficiencies under different monitoring frequencies for the 2020 Technical Rule based on comments received on the 2018 proposal and concluded that the assigned control efficiencies described above can be expected from the corresponding monitoring frequencies using OGI. No other information reviewed since that time indicates that the assigned reduction frequencies are different than previously established and the reduction efficiencies are consistent with what current information indicates. In addition, we also evaluated biennial survey frequency for well sites assuming an achievable reduction frequency of 30 percent, and monthly monitoring where information evaluated indicated monthly OGI monitoring has the potential of reducing emissions up towards 90 percent. 
      Therefore, for the BSER analysis, the emission reduction estimates were calculated as follows, using the 5 tpy methane total site-wide methane emissions as an example. Application of the 50-percent assumption discussed above results in a fugitive emission estimate of 2.5 tpy of methane. The methane emission reductions for an annual program (40 percent reduction), semiannual program (60 percent reduction), and quarterly program (80 percent reduction) would be 1 tpy, 1.5 tpy, and 2 tpy, respectively. 
      It is worth noting that these calculations are based on the expected reductions from "typical" component equipment leaks that occur with well-maintained sites. The EPA is aware of situations where equipment malfunctions related to equipment components can cause large emission events that are described in detail in section XII.A.3. In these cases, we expect the emission reductions associated with the different monitoring frequencies evaluated would be significantly higher than assumed above and is the reason we solicit comment on programs using emerging technologies to identify and quantify large emission sources. As acknowledged above, the 50 percent estimate of fugitive emissions could be over or under-estimating the percentage of emissions that are fugitives, however, the EPA believes this estimate is reasonably representative and captures the average distribution of emissions across typical well sites based on information available at this time. Given the intermittent and stochastic nature of large emission events, it is difficult to apply emission factors that predict the probability of a site experiencing these events within any timeframe. As stated above, the EPA finds it inappropriate to apply a factor that assumes every site is experiencing a large emission event annually given the available data. However, we recognize there is a lot of study on this topic and solicit additional information on large emission events that may further inform the EPA's calculations, including the potential to develop factors that take into account a distribution of emissions across well sites and the associated emissions reductions achieved when large emission events are included in the calculation.
      We evaluated the costs of a monitoring and repair program under various monitoring frequencies. For well sites, the capital costs associated with the fugitives monitoring program were estimated to be $1,030 per well site. These capital costs include the cost of developing the fugitive emissions monitoring plan and purchasing or developing a recordkeeping data management system specific to fugitive emissions monitoring and repair. Consistent with the analyses used for the 2016 NSPS OOOOa and 2020 Technical Rule, the EPA assumes that each company will develop a monitoring plan and recordkeeping system that covers a company-defined area, which is assumed to include 22 well sites. This assumption is used because there are several elements of the fugitive monitoring program that are not site-specific. The total company-defined area (22 well site) capital costs are divided evenly to arrive at the $1,030 capital cost per well site estimate. 
      When evaluating the annual costs of the fugitive emissions monitoring and repair requirements (i.e., monitoring, repair, repair verification, data management licensing fees, recordkeeping, and reporting), the EPA considers costs at the individual site level. Estimates for these costs were updated extensively as part of the 2020 Technical Rule, and the EPA has made further updates for this proposal based on more recent information and to add costs related to the repair of intermittent controllers that are not meeting the proposed standard to not vent when idle. With these updates, the estimated annual costs of the fugitive emissions program at well sites are estimated to range from $2,490 for biennial monitoring to $8,140 for monthly monitoring. These total annual costs include annualization of the up-front cost at 7 percent interest rate over 8 years. We note these costs are representative of the average annual costs expected at well sites, where larger sites may have larger costs associated with longer surveys or potentially more repairs, while smaller sites may experience the opposite with shorter surveys or potentially less repairs. Therefore, we believe the costs developed for well sites are representative of OGI fugitives monitoring program costs and reflect the best information available at this time. 
      At well sites, there are savings associated with the gas not being released. The value of the natural gas saved is assumed to be $3.13/Mcf of recovered gas. Annual costs were also calculated considering these savings.
      As discussed in the introduction to this section and in section XI.C, intermittent pneumatic controllers are designed to vent during actuation only, but these devices are known to malfunction and operate incorrectly which causes them to release natural gas to the atmosphere when idle. For sites that do not have electricity located in the production segment (well sites, gathering and boosting stations, and centralized tank batteries) and in the transmission and storage segment, the EPA is proposing to define intermittent natural gas-driven pneumatic controllers as an affected facility and proposing to apply a standard that these controllers only vent during actuation and not when idle. See section XII.C on pneumatic controllers for a full explanation of this standard. While these intermittent controllers are their own separate affected facility, we are proposing that they be monitored in conjunction with the fugitive emissions components located at the same well site to verify proper actuation and that venting does not occur during idle times. For this reason, the cost of monitoring these intermittent controllers are evaluated in this discussion regarding fugitive emissions. We have included an additional cost to repair a potentially malfunctioning or improperly operating controllers ($600) in the annual cost of the fugitive emissions program presented above. 
      We created a matrix that includes, for each site-wide methane emission level, the capital (up front) cost, annual costs (with and without the consideration of savings), emission reductions for methane and VOC, and cost effectiveness (dollar per tons of emission reduction). Cost effectiveness was calculated using two approaches; the single pollutant approach where all the costs are assigned to the reduction of one pollutant; and the multipollutant approach, where half the costs are assigned to the methane reduction and half to the VOC reduction, see discussion in preamble section IX. This was repeated for each site-wide methane emissions level for each monitoring frequency. There were several trends shown in this matrix. As noted above, the same annual cost was applied for each monitoring frequency across all site-wide emission levels. Therefore, as the emissions (and potential emission reductions) increased, the fugitive emissions monitoring became more cost-effective. For example, for semiannual monitoring, the cost effectiveness ranged from $10,700 per ton of methane reduced (for a 1 tpy site-wide methane site) to $210 per ton (for a 50 tpy site-wide methane site). Also, because the emission reduction increase was greater than the cost increase with increasing monitoring frequency, the fugitive emissions monitoring became more cost-effective with increasing monitoring frequency. For example, for a 10 tpy site-wide methane site, the methane cost effectiveness for annual monitoring was $1,500 per ton, $1,070 per ton for semiannual monitoring, and $1,050 per ton for quarterly monitoring. This trend did not extend to monthly monitoring, as the cost of monthly monitoring increases significantly (almost double) compared to quarterly monitoring, while the emission reduction only increased by 10 percent. The complete matrix is available in the TSD for this rulemaking.
      The next step in the EPA's BSER analysis was to balance combinations of the baseline site-wide emission level and monitoring frequency where the maximum emission reduction could be achieved while the cost effectiveness was considered reasonable. First, the EPA determined the minimum baseline methane emissions above which ground based OGI monitoring was considered reasonable. To do this, we evaluate the baseline methane emissions in increments of 1 tpy and then identified the lowest baseline for each monitoring frequency that was reasonable. When considering the single-pollutant approach, we found that monitoring at any frequency may be reasonable when the total site-level baseline methane emissions are at least 5 tpy. When considering the multipollutant approach, we found that baseline may shift to at least 4 tpy total site-level baseline methane emissions. Table 14 summarizes this information for each monitoring frequency evaluated. 
TABLE 14. SUMMARY OF EMISSION REDUCTIONS AND COST-EFFECTIVENESS FOR SITE-LEVEL BASELINE METHANE EMISSIONS OF 4 AND 5 TPY
                             Monitoring Frequency
                            Annual Cost ($/yr/site)
                     Methane Emission Reduction (tpy/site)
                       VOC Emission Reduction (tpy/site)
                               Single-Pollutant
                                Multipollutant
                                       
                                       
                                       
                                       
                          Methane Cost-Effectiveness
                                    ($/ton)
                            VOC Cost-Effectiveness
                                    ($/ton)
                          Methane Cost-Effectiveness
                                    ($/ton)
                            VOC Cost-Effectiveness
                                    ($/ton)
5 tpy site-level baseline methane emissions
Biennial
                                    $2,500
                                     0.75
                                     0.21
                                    $3,300
                                    $12,000
                                    $1,700
                                    $6,000
Annual
                                    $3,000
                                     1.00
                                     0.28
                                    $3,000
                                    $10,800
                                    $1,500
                                    $5,400
Semiannual
                                    $3,200
                                     1.50
                                     0.42
                                    $2,100
                                    $7,700
                                    $1,100
                                    $3,800
Quarterly
                                    $4,200
                                     2.00
                                     0.56
                                    $2,100
                                    $7,600
                                    $1,100
                                    $3,800
Monthly
                                    $8,100
                                     2.25
                                     0.63
                                    $3,600
                                    $13,000
                                    $1,800
                                    $6,500
4 tpy site-level baseline methane emissions
Biennial
                                    $2,500
                                     0.60
                                     0.17
                                    $4,200
                                    $14,000
                                    $2,100
                                    $7,500
Annual
                                    $3,000
                                     0.80
                                     0.22
                                    $3,700
                                    $13,500
                                    $1,900
                                    $6,700
Semiannual
                                    $3,200
                                     1.20
                                     0.33
                                    $2,700
                                    $9,600
                                    $1,300
                                    $4,800
Quarterly
                                    $4,200
                                     1.60
                                     0.44
                                    $2,600
                                    $9,500
                                    $1,300
                                    $4,700
Monthly
                                    $8,100
                                     1.80
                                     0.50
                                    $4,500
                                    $16,300
                                    $2,300
                                    $8,100

      Based on the information summarized in Table 14, the costs appear to be reasonable for either semiannual or quarterly monitoring when site-level baseline methane emissions are 5 tpy or greater under the single pollutant approach or 4 tpy or greater under the multipollutant approach. Since 2016, owners and operators have been conducting semiannual monitoring pursuant to NSPS OOOOa, state requirements, or voluntarily, thus allowing us to conclude the cost is reasonable for that frequency. Additionally, the cost is comparable to the costs found reasonable in the both the 2016 NSPS OOOOa and 2020 Technical Rule for both the single pollutant approach for methane or multipollutant approach. The additional emission reductions achieved by adopting a minimum threshold of 4 tpy are 0.3 to 0.4 tpy for semiannual and quarterly monitoring, respectively, but it is unclear if there would be additional costs associated with achieving those reductions. We can, however, evaluate the incremental costs of going from semiannual to quarterly monitoring. The incremental costs of semiannual to quarterly monitoring for an emissions baseline of 5 tpy methane is $2,000/ton methane and $7,200/ton VOC. The incremental costs of semiannual to quarterly monitoring for an emissions baseline of 4 tpy methane is $2,500/ton methane and $9,000/ton VOC. While $2,500/ton methane reduced may be somewhat higher than what we can confidently conclude is cost-effective, $9,000/ton VOC reduced is well above what we have historically considered cost-effective for VOC reduction, as is $7,200/ton VOC reduced. Given the uncertainty of the incremental costs associated with achieving the additional 0.3 tpy methane reductions (0.09 tpy VOC reductions) when setting an emission threshold of 4 tpy, the EPA is not proposing using this minimum threshold. Therefore, the EPA is proposing that semiannual monitoring is appropriate for well sites with total site-level baseline methane emissions of at least 5 tpy.   
      Where total site-level baseline methane emissions are below 5 tpy, the information currently available to the EPA does not show ground based OGI monitoring at any frequency to be cost-effective. The EPA seeks comment on all aspects of our analysis, including comment on our estimates of the costs and emission reduction benefits associated with OGI monitoring at this cohort of sites or other information and data that would support the feasibility and cost-effectiveness of OGI monitoring at these sites. We also believe that at emissions below 5 tpy methane, a more targeted approach to identifying which well sites are actually experiencing large emission events (which the emerging technologies for which the EPA seeks comment in section X.A.1 would enable) may be more appropriate than requiring ground based OGI surveys at regular frequencies. For example, if the EPA were to instead adopt a program that utilizes emerging technologies in a supplemental proposal, all owners and operators of well sites (regardless of site-level baseline methane emissions estimates) would have the ability to screen for emissions across a larger area, and thus target ground OGI surveys at those sites where screening identifies emissions, instead of requiring OGI at a set frequency at large numbers of sites that may not have fugitive emissions at the time of the survey.  As noted elsewhere in this section, the EPA seeks information, data and analysis that would support the establishment of ongoing monitoring requirements at all well sites, including at the cohort of sites with baseline methane emissions below 5 tpy, using these emerging technologies  -  including information on the capabilities of these emerging technologies, methodologies for their use, and the costs and emission reductions associated with using these emerging technologies as part of a regulatory monitoring regime.  Finally, as we stated in section XX, for sites below 5 tpy, we are proposing obligations to demonstrate that their emissions are and remain below 5 tpy.
      Further, the EPA believes there is a subset of well sites (i.e., wellhead only well sites) that will never have baseline methane fugitive emissions of 5 tpy or greater, therefore, the proposed rule would not define these sites as affected facilities, thus removing the need for these sites to determine baseline emissions. As defined in the 2020 Technical Rule, a "wellhead only well site" is "a well site that contains one or more wellheads and no major production and processing equipment." The term "major production and processing equipment" is defined as including reciprocating or centrifugal compressors, glycol dehydrators, heater/treaters, separators, and storage vessels collecting crude oil, condensate, intermediate hydrocarbon liquids, or produced water. As described earlier in this section, sites will calculate their baseline methane emissions using a combination of population-based emission factors and storage vessel emissions. The population-based emission factors include emissions from wellheads, reciprocating and centrifugal compressors, glycol dehydrators, heater/treaters, separators, natural gas-driven pneumatic pumps, and natural gas-driven pneumatic controllers (both continuous and intermittent). By definition, a wellhead only well site would not have emissions associated with the major production and processing equipment. Further, it is our understanding that the emission factors for natural gas-driven pneumatic pumps and natural gas-driven pneumatic controllers are representative of pneumatic devices that are associated with this major production and processing equipment, and not pneumatic devices associated with the wellhead itself. Additionally, storage vessels would not be present. Therefore, the only emissions would be calculated based on the fugitive emissions components associated with the wellhead, which we believe would never be above 5 tpy.
      Having established a baseline where semiannual monitoring is reasonable (5 tpy methane), we next evaluated whether there are baseline emissions where quarterly or monthly monitoring is reasonable. Following the same incremental procedure discussed above, we evaluated methane emissions in 1 tpy increments starting at 5 tpy to determine when quarterly or monthly monitoring is reasonable. Table 15 summarizes the incremental costs of semiannual to quarterly, and quarterly to monthly, for baseline methane emissions between 5 tpy and 20 tpy (in 5 tpy increments). 
TABLE 15. SUMMARY OF INCREMENTAL COST-EFFECTIVENESS FOR FUGITIVE MONITORING AT WELL SITES
                  Site-Level Baseline Methane Emissions (tpy)
                      Incremental Annual Cost ($/yr/site)
               Incremental Methane Emission Reduction (tpy/site)
                 Incremental VOC Emission Reduction (tpy/site)
                        Incremental Cost-Effectiveness 
                                       
                                       
                                       
                                       
                                Methane ($/ton)
                                  VOC ($/ton)
Incremental for semiannual to quarterly
5
                                    $1,000
                                     0.50
                                     0.14
                                    $2,000
                                    $7,200
10
                                    $1,000
                                     1.00
                                     0.28
                                    $1,000
                                    $3,600
15
                                    $1,000
                                     1.50
                                     0.42
                                     $670
                                    $2,400
20
                                    $1,000
                                     2.00
                                     0.55
                                     $500
                                     $1800
Incremental for quarterly to monthly
5
                                    $3,900
                                     0.25
                                     0.07
                                    $15,700
                                    $56,600
10
                                    $3,900
                                     0.50
                                     0.14
                                    $7,900
                                    $28,300
15
                                    $3,900
                                     0.75
                                     0.21
                                    $5,200
                                    $18,900
20
                                    $3,900
                                     1.00
                                     0.28
                                    $3,900
                                    $14,100
      
      The information summarized in Table 15 clearly demonstrates that monthly OGI monitoring is not reasonable at any of these thresholds. Therefore, we are not proposing monthly OGI monitoring for any well sites. For the incremental costs of going from semiannual to quarterly monitoring, it appears reasonable at either 10, 15, or 20 tpy methane thresholds. The EPA also weighed information provided by environmental groups that suggested gas well sites with production above 15 boe per day have baseline site emissions of 15.5 tpy methane. As stated in section X.A.1, while the EPA has proposed to remove the exemption for low production well sites in NSPS OOOOa (and chosen to utilize site-level emissions in NSPS OOOOb), we are still concerned this analysis may not adequately reflect the cost burden on small businesses, many of which own or operate lower producing well sites. Therefore, the EPA is proposing to require quarterly OGI monitoring at well sites with total site-level baseline methane emissions of 15 tpy or greater (which data indicates represents non-low producing sites), and semiannual OGI monitoring at well sites with total site-level baseline methane emissions greater than or equal to 5 tpy and less than 15 tpy. 
      In summary, based on the analysis described above, the EPA selected three baseline total site-wide methane emission levels to represent thresholds that would determine the monitoring frequency. These are (1) well sites with total site-wide methane emissions less than 5 tpy (baseline VOC emissions 1.59 tpy), (2) well sites with total site-side methane emissions of 5 tpy or greater but less than 15 tpy, and (3) well sites with total site-wide methane emissions of 15 tpy or greater (baseline VOC emissions 4.17 tpy). The corresponding proposed monitoring frequency for these thresholds are (1) no monitoring for sites with baseline methane emissions less than 5 tpy (but sites must calculate and maintain a record of the baseline emission calculation), (2) semiannual monitoring for sites with baseline methane emissions greater than or equal to 5 tpy but less than 15 tpy, and (3) quarterly monitoring for sites with baseline methane emissions greater than or equal to 15 tpy. 
      Throughout the development of the 2016 NSPS OOOOa, and in subsequent analyses and rulemaking actions, industry stakeholders have consistently stated that the fugitive monitoring requirements are particularly burdensome for small wells that have low production and thus, low revenues. As explained above, the EPA developed and analyzed separate "low production" model plants in the past but has since recognized that there is not always a direct correlation between production and fugitive emissions due to the significant variation in the operations, and types and quantity of equipment at well sites across the U.S. irrespective of production level. The lack of a direct correlation between production and fugitive emissions has also been pointed out by commenters that represent both industry and environmental NGOs. We think that the burden imposed by the fugitive monitoring requirements differs depending on the numbers and types of equipment required to be monitored; therefore, we anticipate low production well sites with few major production and processing equipment would likely have baseline fugitive methane emissions below 5 tpy and thereby not be subject to the proposed ground based OGI monitoring frequencies. We believe that this revised approach to establishing fugitive emission monitoring requirements will address the concerns of small operators, while focusing leak detection and repair requirements on sites that are estimated to have greater fugitive emissions and correspondingly greater potential to reduce those emissions cost-effectively. Each site will calculate their site-wide methane emissions based on the actual equipment on site, and determine the frequency of monitoring required, if any. The EPA is specifically soliciting comments on how this revised approach helps identify those sources that have higher potential for fugitive emissions and if it lessens the burden on small sites with limited equipment and emission reductions potential. 
      The 2016 NSPS OOOOa requires a fugitive emissions monitoring and repair program, where well sites are monitored semiannually. Well sites have successfully met this standard, though the EPA does not have information on how many of those sites are owned or operated by small businesses, or the number of low production sites that have been subject to the 2016 NSPS OOOOa standards. Also, several state agencies have rules that require at least semiannual monitoring for well sites. For example, Colorado's Regulation 7 Control of Ozone via Ozone Precursors and Control of Hydrocarbons via Oil and Gas Emissions requires a semiannual inspection frequency for well production facilities with uncontrolled actual VOC emissions between 2 and 12 tpy. Quarterly inspections are required for well sites with uncontrolled actual VOC emissions between 12 and 20 tpy (and between 12 and 50 tpy for facilities with storage tanks). Colorado Regulation 7 requires monthly inspections for well production facilities without storage tanks with uncontrolled actual VOC emissions above 20 tpy (and above 50 tpy for facilities with storage tanks). California requires quarterly inspections for all well sites under its LDAR requirements in Code of Regulations, Title 17, Division 3, Chapter 1, Subchapter 10 Climate Change, Article 4, Article Subarticle 13: Greenhouse Gas Emission Standards for Crude Oil and Natural Gas Facilities. Ohio's General Permits 12.1 and 12.2 initially require quarterly monitoring for well sites, followed by a reduced monitoring frequency of semiannual or annual monitoring. These examples of state rules requiring monitoring as frequently as monthly in some cases, and production continuing is a demonstration of the reasonableness of monitoring fugitive emissions components on at least a semiannual basis for well sites. 
      No secondary gaseous pollutant emissions or wastewater are generated during the monitoring and repair of fugitive emissions components. There are some emissions that would be generated by contractors conducting the OGI camera monitoring associated with driving to and from the site for the fugitive emissions survey. Using AP-42 mobile emission factors and assuming a distance of 70 miles to the well site, the emissions generated from semiannual monitoring at a well site (140 miles to and from the well site twice a year) is estimated to be 0.35 lb/yr of hydrocarbons, 6.0 lb/yr of CO and 0.40 lb/yr of NOx. No other secondary impacts are expected. We do not believe these secondary emissions are so significant as to affect our conclusions described in the cost-effectiveness analysis. 
      In light of the above, we find that BSER for reducing methane and VOC emissions from well sites with site-level baseline methane emissions less than 5 tpy is no ground based OGI monitoring. For well sites with site-level baseline methane emissions greater than and equal to 5 tpy and less than 15 tpy, we find that BSER is semiannual monitoring. For well sites with site-level baseline methane emissions greater than and equal to 15 tpy, we find that BSER is quarterly monitoring. Therefore, for NSPS OOOOb, we are proposing to require semiannual monitoring for well sites with site-level baseline methane emissions greater than and equal to 5 tpy and less than 15 tpy, and quarterly monitoring for well sites with site-level baseline methane emissions greater than and equal to 15 tpy. This monitoring includes monitoring of subcategory 2 natural gas-driven intermittent pneumatic controllers to ensure they are not venting during idle. While the EPA believes that well sites with intermittent controllers will also have equipment with emissions that will exceed the 5 tpy minimum threshold proposed, we are soliciting comment on whether there are instances where intermittent controllers are located at well sites that would not exceed 5 tpy for site-level baseline methane emissions, and on appropriate means to ensure compliance with the proposed standard for subcategory 2 intermittent controllers to not vent when idle.
 b. Fugitive Emissions from Compressor Stations
       The EPA continues to utilize the model plant approach in estimating baseline fugitive emissions from compressor stations. Unlike well sites, we believe that compressor station designs are less variable and that model plants are an effective construct to analyze fugitive emission control programs. There are three types of compressor stations in the Crude Oil and Natural Gas source category: (1) gathering and boosting stations, (2) transmission stations, and (3) storage stations. The equipment associated with these compressor stations vary depending on the volume of natural gas that is transported and whether any treatment of the gas occurs, such as the removal of water or hydrocarbons. The model plants developed for these sites include all equipment (including piping and associated components, compressors, generators, separators, storage vessels, and other equipment) and associated components (e.g., valves and connectors) that may be sources of fugitive emissions associated with these operations. One model plant was developed for each of the three types of compressor stations described above, which are discussed in detail in the 2020 TSD and in the TSD supporting this action. For gathering and boosting stations, the fugitive baseline emissions were estimated to be 16.6 tpy of methane and 4.6 tpy of VOC. For transmission stations, the fugitive baseline emissions were estimated to be 40.4 tpy of methane and 1.1 tpy of VOC. For storage stations, the fugitive baseline emissions were estimated to be 142.2 tpy of methane and 3.9 tpy of VOC. 
      As with well sites, in the original BSER analysis for the 2016 NSPS OOOOa rulemaking, two options for reducing fugitive methane and VOC emissions at compressor stations were identified, which were (1) a fugitive emissions monitoring program based on individual component monitoring using EPA Method 21 for detection combined with repairs and (2) a fugitive emissions monitoring program based on the use of OGI detection combined with repairs. Finding that both methods achieve comparable emission reduction but OGI was more cost effective, the EPA ultimately identified quarterly monitoring of compressor stations using OGI as the BSER. 81 FR 35862. While there are several new fugitive emissions technologies under development, the EPA needs additional information and better understanding of these technologies, and they are therefore not being evaluated as potential BSER at this time. For this analysis for both the NSPS and the EG, we re-evaluated OGI as BSER. In the discussion below, we evaluate OGI control options based on varying the frequency of conducting the survey and fugitive emissions repair threshold (i.e., the visible identification of methane or VOC when an OGI instrument is used). For this analysis, we considered annual, semiannual, quarterly, and monthly survey frequency for compressor stations. 
      In 2015, we evaluated the potential emission reductions from the implementation of an OGI monitoring program where an emission reduction of 40, 60 and 80 percent for annual, semiannual, and quarterly monitoring survey frequencies, respectively, were determined appropriate. No other information reviewed since 2015 indicates that the assigned reduction frequencies are different than previously established and the reduction efficiencies are consistent with what current information indicates. In addition, we also evaluated monthly monitoring for compressor stations where information evaluated indicated monthly OGI monitoring has the potential of reducing emissions up towards 90 percent. 
      We evaluated the costs of monitoring and repair under various monitoring frequencies described above, including the cost of OGI monitoring via the camera survey, repair costs, resurvey costs, monitoring plan development and the cost of a recordkeeping system. For compressor stations, the capital cost associated with the fugitives monitoring program were estimated to be $3,090 for each gathering and boosting compressor station, which includes development of a fugitive emissions monitoring plan for a company-defined area (assumed to include 7 gathering and boosting compressor stations) and database management development or licensing for recordkeeping. These capital costs are divided evenly amongst the 7 gathering and boosting compressor stations in the company-defined area for purposes of the model plant analysis, consistent with the 2016 NSPS OOOOa and 2020 Technical Rule analyses. The capital cost associated with the fugitives monitoring program for transmission and storage compressor stations was estimated at $23,880, which is for a single transmission and storage compressor station. The annual costs include the capital recovery cost (calculated at a 7 percent interest rate for 10 years), survey and repair costs, database management fees, and recordkeeping and reporting costs. The annual costs estimated for compressor stations range from $6,350 for annual monitoring to $33,220 for monthly monitoring at gathering and boosting compressor stations. For transmission compressor stations, the annual costs estimated range from $12,900 for annual monitoring to $39,770 for monthly monitoring. For storage compressor stations, the annual costs estimated range from $17,000 for annual monitoring to $43,860 for monthly monitoring. 
      As discussed above, the EPA is proposing that natural gas-driven intermittent vent controllers at production and natural gas transmission sites without electricity would be subject to a standard that prohibits emissions when the controller is idle. Intermittent pneumatic controllers are designed to vent during actuation only, but these devices are known to malfunction and operate incorrectly which causes them to release natural gas to the atmosphere when idle. For sites that do not have electricity located in the production segment (well sites, gathering and boosting stations, and centralized tank batteries) and in the transmission and storage segment, the EPA is proposing to define intermittent natural gas-driven pneumatic controllers as an affected facility and proposing to apply a standard that these controllers only vent during actuation and not when idle. See section XII.C on pneumatic controllers for a full explanation of this standard. We have determined that it would be efficient and reasonable to verify proper actuation and that venting does not occur during idle times by proposing that these devices are monitored along with fugitive emissions components at a site to ensure these devices are meeting the standard. For this reason, the EPA has included discussion and analysis of the costs associated with the proposed standard for intermittent pneumatic controllers at sites without electricity here in this section regarding fugitive emissions. We believe the cost of monitoring of intermittent pneumatic controllers will be absorbed by the cost of the fugitive emissions program, and that little to no additional cost would be associated with monitoring these devices on the fugitive emissions components monitoring schedule. Although no specific cost was attributed to monitoring natural gas-driven intermittent controllers, we did include an annual repair cost of $600 to fix controllers identified to be malfunctioning in the annual cost discussed above. If compressor stations have electricity, they would be required to have non-emitting controllers, and no additional costs are expected to be incurred relayed to repair and/or replacement of malfunctioning intermittent vent controllers.
      At gathering and boosting compressor stations there are savings associated with the gas not being released. The value of the natural gas saved is assumed to be $3.13/Mcf of recovered gas. Transmission and storage compressor stations do not own the natural gas; therefore, revenues from reducing the amount of natural gas emitted/lost was not applied for this segment.
      The EPA evaluated the cost-effectiveness of monitoring for each sub-type of compressor station, starting with evaluating whether quarterly monitoring remains the BSER. The 2016 NSPS OOOOa requires a fugitive emissions monitoring and repair program, where compressor stations have to be monitored quarterly. Compressor stations have successfully met this standard. Further, several state agencies have rules that require quarterly monitoring at compressor stations. For example, Colorado's Regulation 7 Control of Ozone via Ozone Precursors and Control of Hydrocarbons via Oil and Gas Emissions requires a semiannual inspection frequency for compressor stations with uncontrolled actual VOC emissions between 2 and 12 tpy, a quarterly inspection frequency for compressor stations with uncontrolled actual VOC emissions between 12 and 50 tpy, and monthly inspections for compressor stations with uncontrolled actual VOC emissions above 50 tpy. California requires quarterly inspections under their LDAR requirements and similarly, Ohio's General Permit 18.1 also requires quarterly monitoring for compressor stations. These examples of state rules, where quarterly monitoring appears to be the lowest monitoring frequency required with one exception where the VOC baseline emissions were extraordinarily high, is a demonstration of the reasonableness of monitoring fugitive emissions components on a quarterly basis for compressor stations.
      Given the apparent reasonableness of quarterly monitoring as discussed above, the EPA evaluated whether it was reasonable to require monthly monitoring for compressor stations. Table 16 summarizes the cost, emission reductions, and cost-effectiveness of quarterly and monthly OGI monitoring at compressor stations for the single pollutant approach, while Table 17 summarizes the multi-pollutant approach. 
TABLE 16: SUMMARY OF THE SINGLE POLLUTANT COST OF CONTROL FOR COMPRESSOR STATION FUGITIVE EMISSIONS MONITORING
                                       
                                  Model Plant
                               Capital Cost ($)
                              Annual Cost ($/yr)
                         Annual Cost w/Savings ($/yr)
                                       
                                   Emission 
                                  Reductions
                           Methane Cost of Control 
                              VOC Cost of Control
                                       
                                       
                                       
                                       
                               Methane (Tons/yr)
                                 VOC (Tons/yr)
                              w/o Savings ($/Ton)
                              w/o Savings ($/Ton)
                             Quarterly Monitoring
Gathering & Boosting
                                    $3,100
                                    $13,400
                                    $11,000
                                     13.3
                                      3.7
                                    $1,000 
                                    $3,600
Transmission
                                    $23,900
                                    $19,900
                                   $19,900 
                                     32.3
                                      0.9
                                     $600 
                                    $22,300
Storage
                                    $23,900
                                    $24,000
                                    $24,000
                                     114.0
                                      3.2
                                     $200 
                                    $7,600
                                            Compressor Program Weighted Average
                                     $900 
                                    $4,400
                              Monthly Monitoring
Gathering & Boosting
                                    $3,100 
                                    $33,200
                                    $30,500
                                     15.0
                                      4.2
                                    $2,200 
                                    $8,000
Transmission
                                    $23,900
                                    $39,800
                                    $39,800
                                     36.4
                                      1.0
                                    $1,100 
                                    $39,500
Storage
                                    $23,900
                                    $43,900
                                   $43,900 
                                     128.2
                                      3.5
                                     $340 
                                    $12,400
                                            Compressor Program Weighted Average
                                    $1,800 
                                    $9,300 
      
TABLE 17: SUMMARY OF THE MULTI-POLLUTANT COST OF CONTROL FOR COMPRESSOR STATION FUGITIVE EMISSIONS MONITORING
      
                                  Model Plant
                               Capital Cost ($)
                              Annual Cost ($/yr)
                         Annual Cost w/Savings ($/yr)
                                       
                                   Emission 
                                  Reductions
                            Methane Cost of Control
                              VOC Cost of Control
                                       
                                       
                                       
                                       
                               Methane (Tons/yr)
                                 VOC (Tons/yr)
                              w/o Savings ($/Ton)
                              w/o Savings ($/Ton)
                             Quarterly Monitoring
Gathering & Boosting
                                    $3,100
                                    $13,400
                                    $11,00
                                     13.3
                                      3.7
                                     $500
                                    $1,800
Transmission
                                    $23,900
                                    $19,900
                                   $19,900 
                                     32.3
                                      0.9
                                     $300
                                    $11,100
Storage
                                    $23,900
                                    $24,000
                                   $24,000 
                                     114.0
                                      3.2
                                     $100
                                    $3,800
                                            Compressor Program Weighted Average
                                     $430
                                    $2,200
                              Monthly Monitoring
Gathering & Boosting
                                    $3,100 
                                    $33,200
                                   $30,500 
                                     15.0
                                      4.2
                                    $1,100
                                    $4,000
Transmission
                                    $23,900
                                    $39,800
                                   $39,800 
                                     36.4
                                      1.0
                                     $550
                                    $19,800
Storage
                                    $23,900
                                    $43,900
                                   $43,900 
                                     128.2
                                      3.5
                                     $200
                                    $6,200
                                            Compressor Program Weighted Average
                                     $900
                                    $4,600
      
      Based on the single pollutant approach, both quarterly and monthly frequencies are reasonable for methane emissions, while only quarterly is reasonable for VOC emissions. Like described for well sites, owners and operators of compressor stations have been monitoring quarterly since 2016 pursuant to NSPS OOOOa, state requirements, or voluntarily, which suggests these costs are reasonable. These costs for quarterly monitoring are also comparable to those found reasonable in both the 2016 NSPS OOOOa and the 2020 Technical Rule. Further, both frequencies are reasonable under the multipollutant approach when considering the total cost-effectiveness compared to a baseline of no OGI monitoring. 
      The EPA then looked at the incremental costs of going from quarterly to monthly monitoring. Quarterly monitoring achieves an emission reduction ranging from 13.3 tpy at gathering and boosting compressor stations to 114 tpy at storage compressor stations. Monthly monitoring achieves additional reductions ranging from 1.7 tpy at gathering and boosting compressor stations to 14.2 tpy at storage compressor stations. However, these additional reductions are achieved at $9,400/ton methane (and nearly $50,000/ton VOC). The EPA finds that achieving these additional emissions reductions is not reasonable for the cost, especially when compared to the very cost-effective reductions achieved by quarterly monitoring with only a fraction of additional reductions realized at monthly monitoring. Based on the cost analysis summarized above, we find that the cost effectiveness of quarterly monitoring for compressor stations is reasonable. 
      Finally, no secondary gaseous pollutant emissions or wastewater are generated during the monitoring and repair of fugitive emissions components. There are some emissions that would be generated by the OGI camera monitoring contractors with respect to driving to and from the site for the fugitive emissions survey. Using AP-42 mobile emission factors and assuming a distance of 70 miles to the compressor station, the emissions generated from quarterly monitoring at a compressor station (140 miles to and from the compressor station four times a year) is estimated to be 0.70 lb/yr of hydrocarbons, 12.0 lb/yr of CO and 0.80 lb/yr of NOx. No other secondary impacts are expected.
      In light of the above, we find that the BSER for reducing methane and VOC emissions from all compressor stations, including gathering and boosting stations, transmission stations, and storage stations is quarterly monitoring for this proposal. Therefore, for NSPS OOOOb, we are proposing to require quarterly monitoring for all compressor stations.
2. EG OOOOc
	The EPA also evaluated BSER for the control of fugitive emissions at existing well sites compressor stations. The findings were that the controls evaluated for new sources for NSPS OOOOb are appropriate for consideration under the EG OOOOc. Further, the EPA finds that the OGI monitoring, methane emission reductions, costs, and cost effectiveness results discussed above for new sources are also applicable for existing sources. 
	Therefore, for the EG OOOOc, the EPA is proposing presumptive standards to require semiannual monitoring for well sites with site-level baseline methane emissions greater than and equal to 5 tpy and less than 15 tpy, and quarterly monitoring for well sites with site-level baseline methane emissions greater than and equal to 15 tpy. This monitoring includes checking natural gas-driven intermittent pneumatic controllers to ensure they are not venting during idle. We find the costs reasonable for existing well sites with total site-level baseline methane emissions greater than or equal to 15 tpy to conduct quarterly OGI monitoring at an incremental cost of $670/ton methane reduced. Further, as we explained above, this 15 tpy threshold is also consistent with site-level baseline emissions presented to the EPA through comments on the 2020 Technical Rule. We are aware that there is a large percentage of existing well sites that are likely owned and operated by small businesses. We continue to be concerned about the burden of frequent OGI monitoring on these small businesses and believe this 15 tpy threshold for the most frequent monitoring (quarterly) may place the majority of well sites owned or operated by small businesses into the less frequent monitoring schedule. Further, based on our evaluation of the well sites with total site-level baseline methane emissions ranging from 5 tpy to 15 tpy, we find that semiannual monitoring is reasonable at $2,100/ton methane reduced, especially when compared to the 2016 NSPS OOOOa and 2020 Technical Rule, which require semiannual monitoring for well sites.
      The EPA also finds, and is proposing, that the BSER for reducing methane emissions from all existing compressor stations, including gathering and boosting stations, transmission stations, and storage stations is quarterly monitoring. For compressor stations, we find that both quarterly (at $430/ton methane reduced) and monthly monitoring (at $900/ton methane reduced) are reasonable, however, at an incremental cost of $9,400/ton methane reduced, monthly monitoring is not reasonable. Therefore, we are proposing quarterly monitoring for existing compressor stations. Therefore, for the EG OOOOc, we are proposing a presumptive standard of quarterly monitoring for all compressor stations.
3. Relationship Between Fugitive Emissions OGI Monitoring Requirements, Emerging Technologies, and Large Emission Events
      As discussed throughout this preamble, the EPA recognizes the existence large emission events. In certain instances, these situations could be caused by severely and continuously leaking components that would be identified and corrected via the routine OGI-based periodic monitoring program, but only on a quarterly or semiannual basis. Moreover, some large emission events are intermittent and stochastic in nature, and may not be identified via these OGI surveys. As discussed at length in section XI.A.1 of this preamble, there are numerous technologies that are already being used, and that continue to emerge, to identify large emission events from oil and natural gas sites. The EPA is seeking comment on how emerging technologies can be used to identify large emissions events as an added layer in addition to routine fugitive emissions surveys. In addition, the EPA is seeking input on how these emerging technologies could potentially be used as an alternative screening work practice in lieu of ground based OGI fugitive emission surveys or with these OGI surveys at a lesser frequency, or to ultimately allow for less frequent OGI surveys.
      Further, the EPA is seeking comment on very simple AVO checks that could be performed in conjunction with the periodic OGI monitoring surveys to help identify potential large emission events. For example, two often-cited causes of super-emitter sources are unlit flares and separator dump valves that are stuck open allowing unintentional gas carry through to emit from storage vessels. The additional time and cost required to perform visual inspections to see if the flare pilot light is working, or to see if a dump valve is stuck open, would be minimal. Yet the benefits of simple AVO inspections could be significant. The EPA is soliciting comment on this concept, as well as comments on the common items that could be included on a checklist for such low-burden AVO inspections in conjunction with fugitive monitoring. 
B. Proposed Standards for Storage Vessels
1. NSPS OOOOb
a. Background
      In the 2012 NSPS OOOO, the EPA established VOC standards for storage vessels. Based on our review of these standards, we are proposing to retain the current standard of 95 percent reduction. However, the EPA is proposing to redefine the affected facility to include a tank battery. Specifically, the EPA is proposing to define a storage vessel affected facility as a single storage vessel or a group of storage vessels that are physically adjacent and that receive fluids from the same source (e.g., well, process unit, or set of wells or process units) or manifolded together for the transfer of liquid or vapors. In addition, the EPA is proposing methane standards for new, reconstructed, and modified sources under the proposed NSPS OOOOb. Both the proposed revised VOC standards and the proposed methane standards would be the same (i.e., 95 percent reduction of emissions from storage vessel affected facilities as defined above in this proposal). These reductions can be achieved by utilizing a cover and closed vent system to capture and route the emissions to a control device that achieves an emission reduction of 95 percent, or by routing the captured emissions to a process.
      Both methane and VOC emissions from storage vessels are a result of working, breathing and flashing losses. Working losses occur when vapors are displaced due to the emptying and filling of storage vessels. Breathing losses are the release of gas associated with daily temperature fluctuations when the liquid level remains unchanged. Flashing losses occur when a liquid with dissolved gases is transferred from a vessel with higher pressure (e.g., separator) to a vessel with lower pressure (e.g., storage vessel), thus allowing dissolved gases and a portion of the liquid to vaporize or flash. In the Crude Oil and Natural Gas source category, flashing losses occur when crude oils or condensates flow into a storage vessel from a separator operated at a higher pressure. Typically, the higher the operating pressure of the upstream separator, the greater the flash emissions from the storage vessel. Temperature of the liquid may also influence the amount of flash emissions. Lighter crude oils and condensate generally flash more hydrocarbons than heavier crude oils.
b. Definition of Affected Facility
      The current standards apply to single storage vessels with potential VOC emissions of 6 tpy or greater, although the EPA has long observed that these storage vessels are typically located as part of a tank battery. 76 FR 52738, 52763 (Aug. 23, 2011). Further, the 6 tpy applicability threshold was established by directly correlating VOC emissions to throughput, was based on the use of a single combustion control device, regardless of the number of storage vessels routing emissions to that control device, and control of 6 tpy VOC was cost effective using that single control device. Id. at 52763-64. Over the years, there have been questions and issues raised regarding how to calculate the potential VOC emissions from individual storage vessels that are part of a tank battery.. The EPA attempted to address this issue through various amendments to NSPS OOOO and NSPS OOOOa, most recently in the 2020 Technical Rule. In the 2020 Technical Rule, the EPA continued to recognize that tank batteries are more prevalent than individual storage vessels. While the 2020 Technical Rule included amendments to the calculation methodology for determining potential VOC emissions from storage vessels that are part of a tank battery, the EPA has now determined that it is more appropriate to evaluate the control of methane and VOC emissions from tank batteries  as a whole instead of each individual storage vessel within a tank battery. In this review the EPA evaluated regulatory options based on the use of a single control device to reduce both methane and VOC emissions from a tank battery, which is consistent with the 2012 NSPS OOOO, 2016 NSPS OOOOa, and subsequent amendments to each of those rules. The EPA believes that this approach will simplify applicability criteria for owners and operators of storage vessels, and more accurately aligns with the EPA's original intent of how storage vessel affected facility status should be determined. 
c. Modification
      Section 60.14(a) of the general provisions to part 60 defines modification as follows: "Except as provided in paragraphs (e) and (f) of this section, any physical or operational change to an existing facility which results in an increase in the emission rate to the atmosphere of any pollutant to which a standard applies shall be considered a modification...." We also note that 40 CFR 60.14(f) states that "Applicable provisions set forth under an applicable subpart of this part shall supersede any conflicting provisions of this section." The EPA understands the difficulty assessing emissions from storage vessels and seeks to provide clarity on actions that are considered modification of a tank battery by explicitly listing these in the proposed NSPS OOOOb. We evaluated circumstances that would lead to an increase in the VOC and methane emissions from a tank battery and therefore constitute a modification of an existing tank battery. A modification of an existing tank battery would then require the tank battery owner or operator to assess the potential emissions relative to the proposed NSPS instead of the EG. 
      The EPA is proposing that a single storage vessel or tank battery is modified when any of the following physical or operational changes are made : (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 single storage vessel or tank battery 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). For both items 1 and 2, even if the type and quantity of fluid processed remains the same, the increased storage capacity will lead to higher breathing losses and thereby increase the VOC emissions from the tank battery relative to the VOC emissions prior to the vessel addition or replacement. Therefore, we conclude that these actions are a modification of the tank battery. However, we are soliciting comment to help us better understand the effect of the proposed definition number 1 and 2 on the number of new storage vessels that would be subject to the NSPS.  Under the current definition of a storage vessel affected facility, which is each single storage vessel that meets the 6 tpy applicability threshold, a new storage vessel that is installed in an existing tank battery is an affected facility (assuming the 6 tpy applicability threshold is met) whether the new storage vessel is a replacement or an addition to the tank battery. However, under the proposed definition number 1 and 2 above, the NSPS is triggered only if the new storage vessel is an addition to the tank battery or is of bigger capacity than the storage vessel it is replacing in a tank battery. We therefore solicit comment on how often a storage vessel in a tank battery is replaced with one that is of bigger capacity, or whether the need to increase a tank battery's capacity is generally accomplished by adding storage vessels as opposed to replacing an existing one with a bigger one. We further solicit comment on whether, under our proposed definition of a tank battery (i.e., a single storage vessel or a group of storage vessels that are physically adjacent and that receive fluids from the same source (e.g., well, process unit, or set of wells or process units)), a new storage vessel installed in a tank battery can and should continue to be treated as an affected facility (assuming it meets the applicability threshold) whether or not it is an additional or a replacement storage vessel.  
      Item 3 will increase the volumetric throughput of the tank battery relative to the throughput prior to storage of the additional fluid. This will increase the working losses and potentially increase the flashing losses from the tank battery, depending on the properties of the new fluid stream. In any event, adding a new fluid stream to an existing tank battery increases the VOC emissions from that tank battery relative to just prior to the addition of a new fluid stream and is therefore considered a modification of 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 single storage vessel or tank battery to determine if the modification may require control of VOC emissions. The existing single storage vessel or tank battery will only become subject to the proposed NSPS if it is modified pursuant to this proposed definition of modification and its potential VOC emissions exceed the proposed 6 tpy VOC emissions threshold.
d. Technology Review
      The available control techniques for reducing methane and VOC emissions from storage vessels include routing the emissions from the storage vessels to a combustion control device or a VRU, which would route the emission to a process (including a gas sales line). These are the same control systems that were evaluated under the 2012 NSPS OOOO. While floating roofs can also be used to reduce emissions from many storage vessel applications, including at natural gas processing plants and compressor stations, floating roofs are not effective at reducing emissions from storage vessels that have flashing losses (e.g., storage vessels at well sites or centralized production facilities). Besides the control options described above, we did not find other available control options through our review, including review of RACT/BACT/LAER Clearinghouse. 
      In the development of the 2012 NSPS OOOO, we found that using either a VRU or a combustion control device could achieve a 95 percent or higher VOC emission reduction efficiency. Available information since then continues to support that such devices can achieve a 95 percent control efficiency for both methane and VOC emissions. We are not proposing to require higher control efficiency because in order to achieve 95 percent control efficiencies on a continuous basis, operators will need to design and operate the control to achieve greater than 95 percent control following control device manufacturer specifications on the maximum and minimum heat loads, inlet backpressure requirements, and recommended maintenance. Additionally, there are field conditions, such as high winds that may influence combustion efficiencies. We also note that, while the EPA established operating and monitoring requirements to ensure flares achieve a 98 percent control efficiency at petroleum refineries in 40 CFR part 63, subpart CC, these requirements include sophisticated monitoring and operational controls that may not be practical or cost effective for small, often unmanned facilities, such as those in the Oil and Natural Gas Industry. They also tend to lead to additional fuel use and secondary impacts than combustion systems targeting to achieve a minimum of 95 percent control efficiency. Also, for storage vessels that are used to store weathered crude oil or natural gasoline (where flashing emissions are negligible), floating roofs are currently an allowed alternative control technique in NSPS OOOOa. Floating roofs have no secondary impacts and the benefit of "product recovery" (through reduced hydrocarbon losses); however, these control systems generally achieve 95 percent control efficiencies, but not 98 percent. Considering these factors, we conclude that, consistent with CAA section 111(a) definition of a "standard of performance," 95 percent control efficiency continues to reflect "the degree of emission limitation achievable" through the application of the BSER for tank batteries (a combustor or a VRU. We solicit comment on the issues described above for requiring higher than 95 percent reduction. 
	During pre-proposal outreach, some small businesses raised a concern that the NSPS OOOOa requirement for a continuous pilot light for a storage vessel control device generated more emissions than it prevented for storage vessels with low emissions. Specifically, small business representatives raised concerns that there are situations where propane or other fossil fuel must be used to maintain continuous pilot lights for flares used as control devices on storage vessels that do not produce enough emissions. The EPA is interested in whether the benefits of reducing emissions with these control devices are negated by the need to burn additional fossil fuels and whether there are additional factors that lead to variability in emissions from storage vessels that could be used to more narrowly target these requirements to limit the unnecessary operation of flares. We are soliciting comment from all stakeholders on this issue. 
e. Control Options and BSER Analysis
      For this proposal, the EPA evaluated regulatory options based on different potential emissions thresholds for VOC and methane. We assumed the potential tank battery emissions were reduced by 95 percent using either a VRU or a combustion control device. Since VRUs recover saleable products, we also estimated the value of the recovered product when VRUs were used. The EPA encourages the use of VRUs to capture and sell the emissions from the storage vessels by classifying VRUs as part of the process, therefore emission recovered would not be included in the potential emissions at a site.
 	For new, modified, or reconstructed sources, we evaluated the cost of control using a single combustion device (or VRU) on a single storage vessel as well as a tank battery made up of multiple storage vessels. To do this, we evaluated the use of a single control device achieving 95 percent reduction of VOC and methane emissions at the following potential emission thresholds: 6 tpy VOC from a single storage vessel; 6 tpy VOC from a tank battery; and 1.3 tpy, 5.3 tpy, 20 tpy, and 50 tpy methane from a tank battery. Based on our cost analysis we concluded that it would not be cost effective to lower the VOC applicability threshold below 6 tpy. 
The estimated all-in capital costs for a single combustion control device are approximately $80,000. The estimated annualized costs include the capital recovery cost (calculated at a 7 percent interest rate for 15 years) and labor costs for operations and maintenance and are estimated at approximately $31,500/yr. The estimated capital costs for a VRU sized for a source with potential VOC emissions of 6 tpy are approximately $32,000 and the estimated annualized costs are estimated at approximately $24,000/yr not considering any potential recovery credits from sales. More information on this cost analysis is available in the Technical Support Document for this proposal.
Based on our analysis, the cost effectiveness of controlling VOC and methane emissions from a tank battery with the potential for VOC emissions of 6 tpy, under the single pollutant approach where all the costs are assigned to the reduction of VOC, on the use a single combustion control device, is $5,540 per ton of VOC eliminated. As explained above, storage vessels are commonly located adjacent to one another as part of tank battery, sharing vapor space and joint piping that collect and route the vapors from the tank battery to a control device, when one is used. The single pollutant cost effectiveness for a VRU to control a tank battery with potential VOC emissions of 6 tpy is approximately $4,000 per ton of VOC eliminated. As shown in section IX, costs ranging from $4,000 to $5,540 per ton of VOC reduced are within the range that the EPA considers to be cost effective for reducing VOC emissions. Because it is cost effective to reduce the VOC emissions from a tank battery with potential VOC emissions of 6 tpy or greater, one of the two targeted pollutants in this action, it is cost effective to reduce both VOC and methane emissions from a single storage vessel or a tank battery at that level. Based on our estimate, a tank battery with potential 6 tpy VOC emissions has potential 1.3 tpy of methane emissions. Because storage vessels contain crude oil, condensate, intermediate hydrocarbons, or produced water, which are approximately 80 percent VOC, the methane emissions from storage vessels are generally less than the VOC emissions.  
      We also evaluated the cost effectiveness at a lower VOC threshold of 3 tpy. As shown in the TSD, the single pollutant cost effectiveness for controlling a tank battery with potential emissions of 3 tpy ranges from $7,500 to $11,000. As shown in section IX, costs ranging from $7,500 to $11,000 per ton of VOC reduced is not within the range that the EPA considers to be cost effective for reducing VOC emissions. Using the multipollutant approach, the VOC cost effectiveness is between $3,800 and $5,500, which is considered reasonable, but the methane cost effectiveness is between $17,000 and $25,000, which is considered unreasonable. Therefore, the 3 tpy VOC control option was not considered reasonable at this time using either the single pollutant or multipollutant approach.
      Our analysis also shows that, under the single pollutant approach where all the costs are assigned to the reduction of methane and zero to VOC, it is cost effective to control a single storage vessel or a tank battery with potential methane emissions of 20 tpy (at costs ranging from $1,250 to $1,660 per ton methane). Based on our estimate, a tank battery with potential methane emissions of 20 tpy would have the potential VOC emissions of 91 tpy, 95 percent of which would be reduced at zero cost. Under the multipollutant cost-effectiveness approach, where half of the cost is allocated to methane reduction and the other half to VOC reduction, it is cost effective to control a tank battery with potential methane emissions of 10 tpy and corresponding potential VOC emissions of 46 tpy, at an average cost of $1,500 per ton methane reduced and $330 per ton VOC reduced. In light of the above, 6 tpy of VOC is the lowest threshold that is cost effective to control both VOC and methane emissions. Therefore, the EPA is proposing to define the affected facility for purposes of regulating both VOC and methane emissions as a tank battery with potential VOC emissions of 6 tpy or greater. 
2. EG OOOOc
      The EPA is proposing presumptive standards for reducing methane emissions from existing storage vessels. For purposes of the EG, we are proposing to define a designated facility as a single storage vessel or tank battery with the potential for methane emissions of 20 tpy or greater. For purposes of the EG, we are proposing the same definition of a storage vessel affected facility, which is a single storage vessel or a group of storage vessels that are physically adjacent and that receive fluids from the same source (e.g., well, process unit, or set of wells or process units). 
      The available controls for reducing methane emissions from existing tank batteries are the same as those for reducing methane and VOC emissions from new, modified and reconstructed tank batteries. In assessing the control costs for existing sources, we applied a 30 percent retrofit factor to the capital and installation costs to account for added costs of manifolding existing storage vessels and installing the control system on an existing tank battery. We considered the same regulatory options based on potential methane emissions thresholds of 1.3 tpy, 5.3 tpy, 20 tpy, and 50 tpy per tank battery. 
      The estimated capital costs for a single combustion control device for emissions in this range are approximately $103,000. The estimated annual costs include the capital recovery cost (calculated at a 7 percent interest rate for 15 years) and labor costs for operations and maintenance and are estimated at approximately $34,000. The costs for VRU are more variable than combustion control systems and dependent on the potential emissions for which the VRU is designed to recover. The estimated capital costs for a VRU sized for a source with potential methane emissions of 20 tpy device are approximately $106,000 and the estimated annualized costs are approximately $49,000/yr not considering any potential recovery credits. With a VRU, the recovered VOC and methane are recovered as salable products. Considering the value of recovered product, the annualized cost for VRU sized to recover potential methane emissions of 20 tpy is estimated to be $26,000/yr. More information on this cost analysis is available in the Technical Support Document for this proposal.
      The resulting cost effectiveness, for the application of a single combustion control device or VRU to achieve a 95 percent emission reduction ranges from $19,000 to $27,400 per ton of methane eliminated at a threshold of 1.3 tpy methane. This cost is not considered reasonable. Next, we evaluated the cost effectiveness at a methane threshold of 5.3 tpy, which ranged from $10,000 to $13,700 per ton of methane reduced, which is also not considered reasonable. At a threshold of 20 tpy methane, the cost effectiveness ranges from $1,400 to $1,800 per ton methane reduced. At a threshold of 50 tpy methane, the cost effectiveness ranges from $340 to $720 per ton methane reduced. When we considered the application of these options at a national level, the overall cost effectiveness of the 20 tpy potential methane emissions threshold was $400 per ton methane reduced without considering product recovery credits and has a net cost savings considering product recovery credits. Additionally, the incremental cost effectiveness of the 20 tpy option relative to the 50 tpy potential methane emissions threshold was approximately $900 per ton additional methane reduced when considering product recovery credits. Based on the cost analysis summarized above, we find that the cost effectiveness for achieving 95 percent emission reduction of methane from a tank battery with potential methane emissions of 20 tpy is reasonable for methane.
3. Legally and Practicably Enforceable Limits
      In addition to the BSER analysis described above, the EPA is clarifying the term "legally and practicably enforceable limits" as it related to storage vessel affected facilities in the proposed NSPS OOOOb and EG OOOOc. In the 2016 NSPS OOOOa, the EPA stated that "any owner or operator claiming technical infeasibility, nonapplicability, or exemption from the regulation has the burden to demonstrate the claim is reasonable based on the relevant information. In any subsequent review of a technical infeasibility or nonapplicability determination, or a claimed exemption, the EPA will independently assess the basis for the claim to ensure flaring is limited and emissions are minimized, in compliance with the rule." See 81 FR 35824, 35844 (June 3, 2016). 
      In the context of storage vessels under both the 2012 NSPS OOOO and 2016 NSPS OOOOa, the EPA has learned that numerous owners and operators claim that their storage vessels are not affected facilities under 40 CFR 60.5365(e) and 40 CFR 60.5365a(e). This claim is made based on a determination that the potential for VOC emissions is less than 6 tpy when taking into account requirements under a legally and practicably enforceable limit in an operating permit or other requirement established under a Federal, state, local or tribal authority. However, when the EPA has reviewed the limits considered by these facilities as legally and practicably enforceable, we have become aware that the limits do not require a reduction in emissions; they are often self-imposed or of such a general nature as to be unenforceable or otherwise lack measures to assure the required emission reduction. For example, a permit contains an emission limit of 2 tpy for a single storage vessel, but does not contain any performance testing requirements, continuous or other monitoring requirements, recordkeeping and reporting, or other requirements that would ensure that emissions are maintained below the emissions limit in the permit. In National Mining Ass'n v. EPA, 59 F.3d 1351 (D.C.Cir.1995), the court explained what constitutes "effective" control in assessing a source's potential to emit. According to the court, while "effective" controls need not be Federally enforceable, "EPA is clearly not obliged to take into account controls that are only chimeras and do not really restrain an operator from emitting pollution." Id. at 1362. The court also emphasized that these non-Federally enforceable controls must stem from state or local government regulations, and not "operational restrictions that an owner might voluntarily adopt." Id. at 1362.  Further, as a general "default rule," the burden of proof falls "upon the party seeking relief." Schaffer ex rel. Schaffer v. Weast, 546 U.S. 49, 57 - 58, 126 S.Ct. 528, 163 L.Ed.2d 387 (2005). 
      In light of the above, the EPA is proposing to include a definition for a "legally and practicably enforceable limit" as it relates to limits used by owners and operators to determine the potential for VOC emissions from storage vessels that would otherwise be affected facilities under these rules. The intent of this proposed definition is to provide clarity to owners and operators claiming the storage vessel is not an affected facility in the Oil and Gas NSPS due to legally and practicably enforceable limits that limit their potential VOC emissions below 6 tpy. This definition is being proposed for NSPS OOOOb and the proposed presumptive standard included in EG OOOOc. This proposed definition of "legally and practicably enforceable limit" is consistent with the EPA's historic position on what is considered "legally and practicably enforceable," as tailored to storage vessels in the oil and gas sector that would otherwise be affected facilities under these rules. The proposed definition is as follows:  
      "For purposes of determining whether a single storage vessel or tank battery is an affected facility, a legally and practicably enforceable limit must include all of the following elements:  
        a quantitative production limit and quantitative operational limit(s) for the equipment, or quantitative operational limits for the equipment;  
  an averaging time period for the production limit in (i) (if a production-based limit is used) that is equal to or less than 30 days; 
  established parametric limits for the production and/or operational limit(s) in (i), and where a control device is used to achieve an operational limit, an initial compliance demonstration (i.e., performance test) for the control device that establishes the parametric limits;  
  ongoing monitoring of the parametric limits in (iii) that demonstrates continuous compliance with the production and/or operational limit(s) in (i); 
  recordkeeping by the owner or operator that demonstrates continuous compliance with the limit(s) in (i-iv); and 
  periodic reporting that demonstrates continuous compliance."  
      In this proposed definition, the EPA is not addressing the various ways in which a state or other authority's permit may be issued since the format of permit issuances varies by jurisdiction. The proposed definition of "legally and practicably enforceable" does not specify limits, monitoring requirements, or recordkeeping. Instead, the owner or operator should work with the permitting authority to establish specific limits, monitoring requirements and recordkeeping that will ensure any permitted emission limit is achieved. Only those limits that include the elements described above will be considered "legally and practicably enforceable" for purposes of determining the potential for VOC emissions from a single storage vessel or tank battery, and thus applicability (or non-applicability) of each single storage vessel or tank battery as an affected facility under the rule.  
      This proposed definition will provide clarity to owners and operators in what limits are necessary to ensure they have appropriately determined their single storage vessels or tank batteries are affected facilities under the proposed NSPS OOOOb or designated facilities under the proposed EG OOOOc. Further, as stated in the 2016 NSPS OOOOa, well-designed rules ensure fairness among industry competitors and are essential to the success of future enforcement efforts. 81 FR 35844. Finally, the EPA has taken into consideration the likely improvements in air quality of using the proposed definition, particularly in communities with EJ concerns (identified using EJSCREEN), given our analysis of prior enforcement conclusions for storage vessels. 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 NOx (about 95 million pounds) achieved through these negotiated resolutions occurred in communities with EJ concerns. The EPA is soliciting comment on this proposed definition from all stakeholders. 
C. Proposed Standards for Pneumatic Controllers
1. NSPS OOOOb 
a. Background
      In the 2012 NSPS OOOO, the EPA established VOC standards for natural gas-driven pneumatic controllers. Specifically, subpart OOOO established a natural gas bleed rate limit of 6 scfh for individual, continuous bleed, natural gas-driven controllers located in the production segment. Continuous bleed, natural gas-driven controllers with a bleed rate of 6 scfh or less are commonly called "low bleed" controllers. However, that rule also allowed for the use of "high bleed" controllers (those with a bleed rate over 6 scfh) where required by functional needs such as response time, safety, and positive actuation. At natural gas processing plants, subpart OOOO prohibited the use of natural gas-driven pneumatic controllers through VOC standard that required a natural gas bleed rate of zero ("zero bleed" or "no bleed"). The rule also included allowances for the use of continuous bleed natural gas-driven controllers at natural gas processing plants where required by functional needs.
      In the 2016 NSPS OOOOa, the EPA extended the 6 scfh natural gas bleed rate standard to the natural gas transmission and storage segment, and established GHG standards for all segments. Effectively, the 2016 NSPS OOOOa required low bleed controllers to reduce methane and VOC emissions from the production and transmission and storage segments and prohibited the use of natural gas-driven pneumatic controllers at natural gas processing plants. The rule included allowances for the use of continuous high bleed controllers in the production and transmission and storage segments and continuous natural gas-driven pneumatic controllers at natural gas processing plants where required by functional needs. Emissions from natural gas-driven intermittent vent pneumatic controllers were not addressed in either the 2012 NSPS OOOO or the 2016 NSPS OOOOa rules. This was because, when operated and maintained properly, methane and VOC emissions from intermittent controllers are substantially lower (by an order of magnitude) than those from other natural gas driven controllers. However, the EPA is now aware that these controllers often malfunction and vent during idle periods. Emissions factors considering this fact show are around four times higher than the factors for low-bleed controllers. Further, as presented in subsection c of this section, methane emissions from intermittent controllers make us a significant portion of the overall methane emissions from all natural gas and petroleum system sources in the GHGI. 
b. Subcategorization and Affected Facility Definitions
      As a result of the review of these requirements and the previous BSER determinations, and the consideration of new information including state regulations that have been enacted since 2016, the EPA is proposing GHG (methane) and VOC standards for natural gas-driven pneumatic controllers in all segments of the industry included in the Crude Oil and Natural Gas source category (i.e., production, processing, transmission and storage).  For the updated BSER analysis, we separated oil and natural gas locations in the production and natural gas transmission and storage categories into two subcategories based on the availability of onsite power: (1) natural gas driven pneumatic controllers at sites with onsite power available (subcategory 1); and (2) natural gas driven pneumatic controllers at sites where onsite power is not available (subcategory 2). For this proposal, the EPA is defining "onsite power" as electricity from the grid or an on-site power generating station capable of providing electricity to the entire site. This would exclude electricity sources such as temporary generators that are only capable of temporarily providing power to select sources. We do not expect this would include solar power, as we are not aware of solar power solutions capable of meeting site-wide electricity needs on a consistent and continuous basis. We are specifically soliciting comment on this definition, including comment on whether solar power is an option to provide site-wide electricity.
      The EPA is proposing two separate types of affected facilities for pneumatic controllers for continuous bleed controllers, an affected facility is each single continuous bleed natural gas-driven pneumatic controller. For intermittent vent controllers, an affected facility is the collection of all natural gas driven intermittent vent controllers at a site. These affected facility definitions apply for pneumatic controllers in both subcategories of the production and transmission and storage segments, as well as for pneumatic controllers in at natural gas processing plants.
      For subcategory 1 sites in the production and natural gas transmission and storage categories with onsite power, we are proposing a requirement that all controllers (continuous bleed and intermittent vent) must have a VOC and methane emission rate of zero. Zero-emissions controllers can include air-driven pneumatic controllers (also referred to as instrument air-driven or compressed air-driven controllers), mechanical controllers, electronic controllers, and self-contained natural gas-driven pneumatic controllers. This proposed standard would apply to both continuous bleed and intermittent vent controllers at these sites. The proposed standard would allow for the use of natural gas-driven pneumatic controllers where required by functional needs, provided that justification is provided in an annual report for this need and maintained in records. While zero emissions controllers would not technically be affected facilities, the EPA would encourage owners and operators to maintain documentation to be able to demonstrate that there are no methane or VOC emissions from the controllers.
      For natural gas-driven pneumatic controllers at subcategory 2 sites in the production and natural gas transmission and storage categories without onsite power, we are proposing to require the use of low bleed controllers, meaning that all continuous bleed, natural gas-driven controllers must have a bleed rate of 6 scfh or less. Note that for continuous bleed pneumatic controllers, the proposed affected facility definition is different than contained in NSPS OOOO and OOOOa. In NSPS OOOOa, the affected facility is defined in 40 CFR 60.5365a(d)(1) as "a single continuous bleed natural gas-driven pneumatic controller operating at a natural gas bleed rate greater than 6 scfh." The emission limitation in 40 CFR 60.5390a(c)(1) is that controllers at sites other than natural gas processing plants "have a bleed rate less than or equal to 6 standard cubic feet per hour." Finally, in 40 CFR 60.5420a(c)(4)(iii), the records required to demonstrate that the pneumatic controller is not an affected facility are "records of the manufacturer's specifications indicating that the controller is designed such that natural gas bleed rate is less than or equal to 6 standard cubic feet per hour." The EPA recognizes the disconnect between a controller being designed by the manufacturer to have a natural gas bleed rate less than or equal to 6 scfh and the controller operating with a natural gas bleed rate less than or equal to 6 scfh. The manufacturer typically specifies process parameters (e.g., system pressure) under which the controller will achieve the designed bleed rate. Operating outside of these parameters can result in a bleed rate and emissions higher than expected, and more significantly, higher than the 6 scfh emission limitation. In addition, the construct of NSPS OOOOa does not assure that low-bleed devices are maintained properly to continue to have a bleed rate of 6 scfh or less. In fact, one study found that emissions from improperly operated or maintained low-bleed pneumatic controllers are a significant source of emissions. The proposed affected facility definition, which would make low-bleed pneumatic controllers affected facilities, would ensure that they continue to operate in a manner consistent with the manufacturer's specifications needed to achieve a bleed rate of 6 scfh or less and that they are maintained properly. The EPA requests comment on this change, as well as comment whether the rule should require periodic monitoring of the bleed rate to demonstrate that the controller is operating at 6 scfh or less.
      For these subcategory 2 sites, we are also proposing a standard for natural gas-driven intermittent controllers. Specifically, this standard would require that these intermittent controllers only vent emissions during actuation and that no emissions occur during idle period. We are proposing to require inspections of natural gas-driven intermittent vent pneumatic controllers to verify proper actuation and this standard is met and that there are no emissions between actuations. These inspections would occur in conjunction with, and on the same timing interval as, the OGI-based monitoring for fugitive emissions (see section XII.A). Lastly, the proposed standard would allow for the use of high bleed gas-driven pneumatic controllers where required by functional needs, provided that justification is provided for this need in an annual report and maintained in records.
      For all natural gas processing plants, we are proposing to require that controllers must have a methane and VOC emission rate of zero (i.e., zero-emissions controllers must be used). We are proposing to slightly change the wording of the standard from subparts OOOO and OOOOa, which require a "bleed rate of zero." Since pneumatic controllers that are powered by compressed air technically have a compressed air bleed rate greater than zero, but the compressed air does not contain any natural gas, methane, or VOC, we are clarifying the standard by proposing to require that pneumatic controllers at natural gas processing plants to have a methane and VOC emission rate of zero. However, as with the previous standards, the proposed NSPS OOOOb allows for the use of natural gas-driven pneumatic controllers that emit natural gas where required by functional needs, provided that justification is provided for this need in an annual report and maintained in records. 
c. Description
      Pneumatic controllers are devices used to regulate a variety of physical parameters, or process variables, using air or gas pressure to control the operation of mechanical devices, such as valves. The valves, in turn, control process conditions such as levels, temperatures and pressures. When a pneumatic controller identifies the need to alter a process condition, it will open or close a control valve. In many situations across all segments of the Oil and Natural Gas Industry, pneumatic controllers make use of the available high-pressure natural gas to operate or control the valve. In these "natural gas-driven" pneumatic controllers, natural gas may be released with every valve movement (intermittent) and/or continuously from the valve control. Pneumatic controllers can be categorized based on the emissions pattern of the controller. Some controllers are designed to have the supply-gas provide the required pressure to power the end-device, and the excess amount of gas is emitted. The emissions of this excess gas are referred to as "bleed," and this bleed occurs continuously. Controllers that operate in this manner are referred to as "continuous bleed" pneumatic controllers. These controllers can be further categorized based on the rate of bleed they are designed to have. Those that have a bleed rate of less than or equal to 6 scfh are referred to as "low bleed," and those with a bleed rate of greater than 6 scfh are referred to as "high bleed." Another type of controller is designed to release gas only when the process parameter needs to be adjusted by opening or closing the valve, and there is no vent or bleed of gas to the atmosphere when the valve is stationary. These types of controllers are referred to as "intermittent vent" pneumatic controllers. A third type of controller releases gas to a downstream pipeline instead of the atmosphere. These "self-contained" types of controllers can be used in applications with very low pressure.
      As discussed above, emissions from natural gas-powered pneumatic controllers occur as a function of their design. Self-contained controllers do not emit natural gas to the atmosphere. Continuous bleed controllers using natural gas as the power source emit a portion of that gas at a constant rate. Intermittent vent controllers using natural gas as the power source are designed to emit natural gas only when the controller sends a signal to open or close the valve, which is called actuation. From continuous bleed and intermittent vent controllers, another source of emissions is from improper operation or equipment malfunctions. In some instances, a low bleed controller may emit natural gas at a higher level than it is designed to do (i.e., over 6 scfh) or an intermittent vent controller could emit continuously or near continuously rather than only during actuation.
      Not all pneumatic controllers are driven by natural gas. At sites with electricity, electrically powered pneumatic devices or pneumatic controllers using compressed air can be used. As these devices are not driven by pressurized natural gas, they do not emit any natural gas to the atmosphere. They do not emit VOC or methane to the atmosphere. In addition, some controllers operate mechanically without a power source or operate electronically rather than pneumatically. At sites without electricity provided through the grid or on-site electricity generation, mechanical controllers and electronic controllers using solar power can be used in some instances.
      The emissions from natural gas-powered pneumatic controllers represent a significant portion of the total emissions from the Oil and Natural Gas Industry. In the 2021 GHGI, the estimated methane emissions for 2019 from pneumatic controllers were 700,000 metric tons methane for petroleum systems and 1.35 million metric tons per year for natural gas systems. These levels represent 45 percent of the total methane emissions estimated from all petroleum systems sources and 21 percent of all methane emissions from natural gas systems. A significant portion of these emissions are from natural gas-driven intermittent vent controllers, which the EPA is proposing to define as an affected facility for the first time in NSPS OOOOb. Of the combined methane emissions from pneumatic controllers in the petroleum systems and natural gas systems production segments, emissions from intermittent vent controllers make up 90 percent of the total. Continuous high bleed and low bleed controllers make up 7 and 3 percent, respectively.
d. Control Options
      In identifying control options for this NSPS OOOOb proposal, we re-examined the options previously evaluated in the rulemakings to promulgate the 2012 NSPS OOOO and the 2016 NSPS OOOOa and also examined state rules with requirements for pneumatic controllers that achieve emission reductions beyond those achieved by NSPS OOOOa. For NSPS subparts OOOO and OOOOa, we identified options for reducing emissions from continuous bleed natural gas-driven pneumatic controllers. These options included using low bleed controllers in place of high bleed controllers, using instrument air systems, using mechanical or electronic controllers and enhanced maintenance (i.e., periodic inspection and repair). For the production and transmission and storage segments, only the option to require low bleed controllers was fully analyzed. Based on the EPA's determination at that time that electricity was "likely unavailable" at production and transmission and storage sites, the EPA did not fully consider instrument air or electronic controllers. The EPA also did not evaluate enhanced maintenance, as it was concluded that the highly variable nature of determining the proper methods of maintaining a controller could incur significant costs. The EPA did not evaluate options to reduce emissions from intermittent vent controllers in either 2011/2012 or 2015/2016.
      Three U.S states (California, Colorado and New Mexico) and two Canadian provinces (Alberta and British Columbia) have rules or proposed rules that achieve emission reductions beyond those achieved by NSPS OOOOa. Starting on January 1, 2019, and subject to certain exceptions, a California rule required that all new and existing continuous bleed controllers must not emit to the atmosphere. The rule allows low bleed devices installed prior to January 1, 2016, to continue to operate, provided that annual testing is performed to verify that the low bleed rate is maintained. A Colorado rule adopted in February 2021, requires that all new controllers be non-emitting, and over a period of two years, a sizeable portion of existing controllers must be retrofit to not have emissions. New Mexico has proposed a rule that would require zero VOC emissions from all controllers located at sites with access to electrical power. The Canadian provinces of Alberta (effective 2022) and British Columbia (effective 2021) require that all new controllers are non-emitting controllers, and the British Columbia rule also requires that controllers at existing natural gas processing plants and compressor stations with total power of 3 megawatts (MW) or more must be non-emitting.
      From this review, several options were identified for the BSER analysis for NSPS OOOOb to reduce methane and/or VOC emissions from natural gas-driven pneumatic controllers. These include the following: (1) use of low bleed natural gas-driven pneumatic controllers in the place of high bleed natural gas-driven pneumatic controllers; (2) use of zero emissions controller technology, including instrument air systems, electronic controllers using electricity from the grid or on-site power station, and electronic controllers using solar power; and (3) require zero emissions from intermittent vent controllers except during actuation.
e. BSER Evaluation 
Production and Transmission and Storage Segments. 
      For this BSER analysis, the EPA is separating the production and transmission and storage segments into two subcategories and determining BSER separately for each subcategory and each segment. These subcategories are those sites that have power and those that do not. As noted above, we are requesting comment on how to clearly define those sites that have power. We are also interested in comments on whether the "with power" subcategory should be limited to those sites that already have electricity on-site, or whether sites that have access to electricity should be included, and how to define "access to" for this purpose.
      Production and Transmission and Storage Sites Without Power (Subcategory 2). For the subcategory of production and transmission and storage sites without power, we evaluated a no emissions of VOC and methane to the atmosphere requirement through the use of solar-powered controllers and a requirement to use low bleed natural gas-driven pneumatic controllers in the place of high bleed natural gas-driven pneumatic controllers. In conjunction with this low bleed requirement, we also evaluated a requirement that natural gas-driven intermittent vent pneumatic controllers only discharge natural gas during actuation.
      Due to lack of grid power or on-site produced power at these sites, the non-emission options are limited. Example of potential non-emission options are solar powered-controllers, mechanical-only controllers, self-contained controllers, and controllers where the emissions are captured and routed to a process. Based on the information available to the EPA during development of this proposal, the only non-emissions option evaluated for sites without power (e.g., electricity) was the use of electronic controllers driven by solar power. The EPA solicits comment on the other potential non-emission options for these sites (mechanical-only controllers, self-contained controllers, and controllers where the emissions are captured and routed to a process). The cost and impacts analysis for solar-powered controllers, which is detailed in the Technical Support Document for this rulemaking, resulted in cost effectiveness values for both methane and VOC that are in the ranges considered reasonable by the EPA. This was the case at production sites and at transmission and storage sites. However, in 2015, we determined that, "At sites without available electrical service sufficient to power an instrument air compressor, only gas driven pneumatic devices are technically feasible in all situations." (80 FR 56623, September 18, 2015). We have no new information to indicate this limitation has been overcome. Therefore, at this time, we are unable to conclude that this non-emissions option represents BSER in this proposal. The EPA solicits comment on this 2015 determination and seeks any information related to these limitations.
      As noted above, several states (including California and Colorado) require the use of non-emissions controllers at all sites, even those without power. Industry commenters on the proposed Colorado rule raised the same technical feasibility issues that have been presented to the EPA in the past, including battery storage capacity issues, weather-related issues, and mechanical issues related to vibration. However, despite these issues being raised, Colorado finalized the requirement that new controllers be non-emission controllers at all sites, even though without power. Since that time, New Mexico proposed a rule that did not require non-emissions controllers at sites without electricity. The EPA is requesting information regarding whether technological advances in solar-powered technology have occurred to the point that solar-powered electronic controllers could be universally feasible.
      Another option evaluated for sites without power was the use of low bleed natural gas-driven pneumatic controllers in the place of high bleed natural gas-driven pneumatic controllers. In the analysis of this option, we examined the reasonableness of implementation, emissions reduction potential, the cost of implementation, and the cost effectiveness in terms of cost per ton of emissions eliminated. 
      The emission reduction potential of using a low bleed in place of a high bleed controller depends on the actual bleed rate of each device, which varies from device to device. Using average emission factors for each device type, the difference in emissions can be estimated on a per-controller basis. We estimated this difference between a low bleed and a high bleed device to be an 84 percent reduction for controllers in the production segment and a 94 percent reduction in emissions in the transmission and storage segment, equating to a difference of 2.1 tpy methane and 0.6 tpy VOC per controller in the production segment and 2.9 tpy methane and 0.08 tpy VOC per controller in the transmission and storage segment. The cost of a new low bleed natural gas-driven pneumatic controller is approximately $255 higher than the cost of a new high bleed device. On an annualized basis, assuming a 15-year equipment lifetime and a 7 percent interest rate, the cost is $28 per year per low bleed controller. Under the single pollutant approach where all the costs are assigned to the reduction of one pollutant, the estimated cost effectiveness is $13 per ton of methane avoided and $48 per ton of VOC avoided per controller in the production segment. Using the multipollutant approach where half the cost of control is assigned to the methane reduction and half to the VOC reduction, the estimated cost effectiveness is $7 per ton of methane avoided and $24 per ton of VOC avoided. When considering the cost of saving the natural gas that would otherwise be emitted for the production segment, the cost effectiveness shows an overall savings under both the single pollutant and multipollutant approaches. For the natural gas transmission and storage segment, the cost effectiveness is $10 per ton methane avoided and $355 per ton VOC avoided per controller using the single pollutant method, and $5 per ton of methane and $178 per ton of VOC avoided per controller using the multipollutant method. Transmission and storage facilities do not own the natural gas; therefore, revenues from reducing the amount of natural gas emitted/lost was not applied for this segment. These values are well within the range of what the EPA considers to be reasonable for methane and VOC using both the single pollutant and multipollutant approaches.  
      We also evaluated a requirement at sites without power that natural gas-driven intermittent vent pneumatic controllers only discharge natural gas during actuations. This emissions reduction option would be required in conjunction with a requirement to use low bleed controllers in place of high bleed controllers. The average emission factor determined by an industry study for natural gas-driven intermittent vent controllers, including both properly and improperly operating controllers, is 9.2 scfh natural gas. Comparing this to the emission factor for a properly operating intermittent vent controller of 0.3 scfh natural gas illustrates the significant potential for reductions from a program that identifies intermittent vent controllers that are improperly operating and repairing, replacing, or altering their operating conditions so they may function properly. To ensure these devices are emitting natural gas only during actuations in accordance with their design, there would be no equipment expenditure or associated capital costs; however, emissions monitoring or inspections, combined with repair as needed, will be necessary to ensure this proper operation is achieved. We considered requiring independent inspections specifically for intermittent vent controllers but concluded that it would be more efficient to couple inspections of these controllers with the inspections of equipment for leaks under the fugitive monitoring program. Therefore, the impacts of the inclusion of inspecting and repairing intermittent vent controllers at sites without electricity are discussed in the fugitive monitoring program (see section XII.A of this preamble).
      The 2012 NSPS OOOO and 2016 NSPS OOOOa require low bleed natural gas-driven pneumatic controllers in the place of high bleed natural gas-driven pneumatic controllers at production and transmission and storage sites, and such sites have successfully met this standard. Further, several state agencies have rules that include requirements to use low bleed natural gas-driven pneumatic controllers in place of high bleed controllers at these types of sites. This is a demonstration of the reasonableness of a requirement to use low bleed natural gas-driven pneumatic controllers in place of high bleed controllers at production and transmission and storage sites without power. The EPA also finds that the costs of control with this option are reasonable. 
      Low bleed pneumatic controllers are a replacement option for high bleed devices that simply bleed less natural gas than would otherwise be emitted in the actuation of pneumatic valves. Neither type generates any wastes or wastewater, and no electricity is required for these natural gas-driven pneumatic controllers. Therefore, there are no secondary impacts expected from the use of low bleed pneumatic devices.
      In light of these determinations, we find that the BSER for NSPS OOOOb for reducing methane and VOC emissions from natural gas-driven controllers at production and transmission and storage sites that do not have power (subcategory 2) is a requirement for continuous bleed controllers to have a natural gas bleed rate less than 6 scfh (low bleed) and that natural gas-driven intermittent vent controllers are required to not vent except when actuating. This operating requirement for intermittent vents is monitored via a requirement to periodically inspect and repair the devices as part of the fugitive monitoring program. In 2012 and 2016, we determined that there were situations where low bleed controllers could not be substituted for high bleed controllers due to functional requirements, such as positive actuation or rapid actuation. We have no information that these technical issues have been overcome, and therefore, we are including an allowance for the use of high bleed controllers where needed due to functional requirements in this BSER determination provided that justification is provided for this need in an annual report and maintained in records. 
      Production and Transmission and Storage Sites with Power (Subcategory 1). For the subcategory of production and natural gas transmission and storage sites with power, the EPA evaluated two options. The first was the option discussed above for sites without power (subcategory 2)  -  to require the of use low bleed natural gas-driven pneumatic controllers in the place of high bleed natural gas-driven pneumatic controllers, along with a requirement that natural gas-driven intermittent vent pneumatic controllers only discharge natural gas during actuation. We also evaluated an option of establishing a non-emissions requirement, which we propose to determine represents the BSER for this subcategory.
      For the requirement to use low bleed natural gas-driven pneumatic controllers in place of high bleed natural gas-driven pneumatic controllers, the costs, emission reduction, and cost effectiveness are the same as presented above for the sites without power. That is, for the production segment the cost effectiveness is $13 per ton for methane and $48 per ton of VOC using the single pollutant method, and $7 per ton of methane avoided and $24 per ton of VOC using the multipollutant method. If the value of the recovered gas is considered, there is an overall savings. For the natural gas transmission and storage segment, the cost effectiveness is $10 per ton methane and $355 per ton VOC using the single pollutant method, and $5 per ton of methane and $178 per ton of VOC avoided per controller using the multipollutant method. As discussed for sites without power, this option would also include a requirement that natural gas-driven intermittent vent pneumatic controllers only discharge natural gas during actuations which would be implemented via the fugitives monitoring and repair program. These values are well within the range of what the EPA considers to be reasonable for methane and VOC using both the single pollutant and multipollutant approaches.
      Unlike sites without power, the EPA is confident that sites with power can utilize pneumatic controllers that are not natural gas-driven controllers, which make a non-emission requirement technically feasible. While applicability of both the 2012 NSPS OOOO and the 2016 NSPS OOOOa are based on an individual pneumatic controller, non-emissions controller options are more appropriately evaluated as "site-wide" controls. While individual natural gas-driven pneumatic controllers can be switched to other types of natural-gas driven pneumatic controllers (e.g., high bleed to low bleed types), the implementation of non-emitting options requires equipment that is used for all the controllers at the site. For example, in order to utilize instrument air driven controllers, a compressor and related equipment would need to be installed. The EPA does not believe that a compressor would be installed for a single controller, but rather to provide compressed air to all the controllers at the site. Therefore, to adequately account for the costs of the system, including the controllers and the common equipment, we evaluated these no emissions of VOC and methane to the atmosphere options using "model" plants. 
      These model plants include assumptions regarding the number of each type of pneumatic controller at a site. Emissions were estimated for each of the model plants using a calculation based on of the number of controllers at the plant and emission factors for each controller. Three sizes of model plants (i.e., small, medium, and large) were developed and used for both the production and transmission and storage segments. Each model plant contained one high bleed natural gas-driven controller and increasing numbers of low bleed and intermittent natural gas-driven controllers. For the production segment, the controller-specific emission factors used are from a study conducted by the American Petroleum Institute, and are 2.6 scfh, 16.4 scfh, and 9.2 scfh total natural gas emissions for low bleed, high bleed, and intermittent bleed controllers, respectively. For the transmission and storage segment, the emission factors from GHGRP subpart W were used, which are 1.37 scfh, 18.2 scfh, and 2.35 scfh for low bleed, high bleed, and intermittent bleed controllers, respectively. It was assumed that the portion of natural gas that is methane is 82.9 percent in the production segment and 92.8 percent in the transmission and storage segment. Further, it was assumed that VOCs were present in natural gas at a certain level compared to methane. The specific ratios assumed were 0.278 pounds VOC per pound methane in the production segment and 0.0277 pounds VOC per pound methane in the transmission and storage segment. This information results in estimated emissions for a single natural gas-driven pneumatic controller in the production segment of 0.39, 2.48, and 1.39 tpy methane and 0.1, 0.7, and 0.4 tpy VOC per low bleed, high bleed, and intermittent vent controller, respectively. The emissions for a single natural gas-driven pneumatic controller in the transmission and storage segment are 0.23, 3.08, and 0.40 tpy methane and 0.006, 0.08, and 0.01 tpy VOC per low bleed, high bleed, and intermittent vent controller, respectively.  
      Based on the factors described above and the number of each type of controller in each model plant, baseline emissions for the model plants were calculated. For the production model plants, the baseline emissions were calculated to be 5.7 tpy methane and 1.6 tpy VOC for the small model plant (assumes fewer controllers on site than medium plant), 11.2 tpy methane and 3.1 tpy VOC for the medium model plant (assumes more controllers on site than small plant), and 24.9 tpy methane and 6.9 tpy VOC for the large model plant (assumes more controllers on site than the medium plant). For the transmission and storage model plants, the baseline emissions were calculated to be 4.6 tpy methane and 0.1 tpy VOC for the small model plant, 5.7 tpy methane and 0.2 tpy VOC for the medium model plant, and 10.0 tpy methane and 0.3 tpy VOC for the large model plant. For detailed information on the configuration of these model plants and the calculation of the baseline emissions, see the Technical Support Document for this rulemaking, which is available in the docket.
      For sites with available electricity, two non-emissions options were identified. These include the use of electronic controllers and the use of instrument air controllers. Instrument air systems use compressed air as the signaling medium for pneumatic controllers and pneumatic actuators, whereas electronic controllers send an electric signal to an electric actuator (rather than sending a pneumatic signal to a pneumatic actuator). Both of these options require electricity to operate. As instrument air systems, which are usually installed at facilities where there is a high concentration of pneumatic control valves and the presence of an operator that can ensure the system is properly functioning, we evaluated the use of instrument air for large facilities with more controllers and the use of electronic controllers at small and medium-sized facilities with less controllers. The emission reduction potential of using these non-emissions controllers rather than natural-gas-driven pneumatic controllers is 100 percent since these systems eliminate natural gas emissions.
      For the small and medium-sized model plants, the non-emissions option evaluated was the use of electronic controllers. The respective emissions reduction for small and medium-sized plants would be 5.7 and 11.2 tpy methane and 0.7 and 1.6 tpy VOC in the production segment and 4.1 and 5.7 tpy methane and 0.09 and 0.1 tpy VOC in the transmission and storage segment. The cost of a new electronic controller system is estimated to be $26,000 and $46,000, for small and medium-sized plants respectively. The estimated annualized capital costs, assuming a 15-year equipment lifetime and a 7 percent interest rate, are $2,780 and $5,040 for the small and medium-sized plants, respectively. 
      For the production segment, under the single pollutant approach, the estimated cost effectiveness is $500 per ton of methane avoided and $1,780 per ton of VOC avoided for a small plant and $450 per ton of methane avoided and $1,620 per ton of VOC avoided for a medium-sized plant. Using the multipollutant approach where half the cost of control is assigned to the methane reduction and half to the VOC reduction, the estimated cost effectiveness is $250 per ton of methane avoided and $890 per ton of VOC avoided for a small plant and $225 per ton of methane avoided and $810 per ton of VOC avoided for a medium-sized plant in the production segment. When considering the cost of saving the natural gas that would otherwise be emitted for the production segment, the cost effectiveness is $300 per ton of methane avoided and $1,070 per ton of VOC avoided for a small plant and $250 per ton of methane avoided and $900 per ton of VOC avoided for a medium-sized plant. Using the multipollutant approach, the estimated cost effectiveness is $150 per ton of methane avoided and $530 per ton of VOC avoided for a small plant and $130 per ton of methane avoided and $450 per ton of VOC avoided for a medium-sized plant in the production segment. These values are well within the range of what the EPA considers to be reasonable for methane and VOC using both the single pollutant and multipollutant approaches.
      For the natural gas transmission and storage segment, the estimated cost effectiveness is $680 per ton of methane avoided and $24,600 per ton of VOC avoided for a small plant and $880 per ton of methane avoided and $32,000 per ton of VOC avoided for a medium-sized plant. Using the multipollutant approach, the estimated cost effectiveness is $340 per ton of methane avoided and $12,300 per ton of VOC avoided for a small plant and $440 per ton of methane avoided and $16,000 per ton of VOC avoided for a medium-sized plant. Transmission and storage facilities do not own the natural gas; therefore, revenues from reducing the amount of natural gas emitted/lost was not applied for this segment. While the cost effectiveness values for VOC are higher than the range of what the EPA considers to be reasonable for VOC, the cost effectiveness for methane is within the range of what the EPA considers to be reasonable for methane using the single pollutant approach.
      For the large model plants, the non-emission reduction option evaluated was the use of instrument air systems. For the production segment, the emissions avoided would be 24.9 tpy methane and 6.9 tpy VOC and 10.0 tpy methane and 0.3 tpy VOC in the transmission and storage segment. The cost of a new instrument air system is estimated to be $96,000 and the estimated annualized capital costs, assuming a 15-year equipment lifetime and a 7 percent interest rate, are $10,500. For the production segment, under the single pollutant approach, the estimated cost effectiveness is $420 per ton of methane avoided and $1,520 per ton of VOC avoided. Using the multipollutant approach, the estimated cost effectiveness is $210 per ton of methane avoided and $760 per ton of VOC avoided. When considering the cost of saving the natural gas that would otherwise be emitted for the production segment, the cost effectiveness is $220 per ton of methane avoided and $800 per ton of VOC avoided. Using the multipollutant approach, the estimated cost effectiveness is $110 per ton of methane avoided and $400 per ton of VOC avoided in the production segment. These values are well within the range of what the EPA considers to be reasonable for methane and VOC using both the single pollutant and multipollutant approaches.
      For the natural gas transmission and storage segment, the estimated cost effectiveness is $1,050 per ton of methane avoided and $38,000 per ton of VOC avoided. Using the multipollutant approach, the estimated cost effectiveness is $530 per ton of methane avoided and $19,000 per ton of VOC avoided. Transmission and storage facilities do not own the natural gas; therefore, revenues from reducing the amount of natural gas emitted/lost was not applied for this segment. While the cost effectiveness values for VOC are higher than the range of what the EPA considers to be reasonable for VOC, the cost effectiveness for methane is within the range of what the EPA considers to be reasonable for methane using the single pollutant approach.
      Note that the annual costs for these non-emissions controllers are based on the annualized capital costs only. While we assume the maintenance costs for electric controllers is less than the costs for natural gas-driven controllers, there are costs associated with the use of electricity that are not incurred for natural gas-driven controllers. We solicit comments on whether such operational costs should be included in these estimates, as well as information regarding these costs.
      The EPA finds that the cost effectiveness for both the low bleed and non-emissions options are reasonable for sites with power in the production and natural gas transmission and storage segments. The incremental cost effectiveness in going from the low bleed option to the non-emissions option is estimated to be $480 and $430 per ton of additional methane eliminated for small and medium-sized plants ($1,200 and $1,000 per ton of VOC), respectively, in the production segment and $670 and $880 per ton of additional methane eliminated for small and medium-sized plants ($20,500 and $28,000 per ton of VOC), respectively, in the transmission and storage segment. The incremental cost effectiveness in going from the low bleed option to the non-emissions option is estimated to be $400 and $1,500 per ton of additional methane and VOC avoided, respectively, for large plants in the production segment and to be $1,040 and $38,000 per ton of additional methane and VOC avoided, respectively, for large plants in the transmission and storage segment. These incremental costs of control do not consider savings for the production segment. The EPA believes the incremental costs of control are reasonable for methane and VOC in the production segment, and for methane in the transmission and storage segment. 
      As discussed above, several states require the use of non-emissions controllers throughout the Oil and Natural Gas Industry, which demonstrates the reasonableness of this option and that there are no technical barriers from using electronic controllers or instrument air at sites in the production and transmission and storage segments with electricity. 
      Secondary impacts from the use of electronic controllers and instrument air systems are indirect, variable, and dependent on the electrical supply used to power the compressor. These impacts are expected to be minimal, and no other secondary impacts are expected.
      In light of the above, we find that the BSER for reducing methane and VOC emissions from natural gas-driven pneumatic controllers at production and transmission and storage sites that have power is the use of non-emissions controllers. Therefore, for NSPS OOOOb, we are proposing to require no emissions of VOC and methane to the atmosphere for all pneumatic controllers at production and transmission and storage sites that have power. The EPA is soliciting comment on how to clearly define those sites that have power. We are also interested in comments on whether the "with power" subcategory 1 should be limited to those sites that already have power on-site, or whether sites that have access to power should be included and how to define "access to" for this purpose. We further seek comment on whether owners and operators should be required to periodically re-evaluate whether a site that has previously been classified as falling into subcategory 2 has subsequently gained access to power, and come into compliance with the standards for subcategory 1 within a reasonable timeframe We also recognize that there may be technical limitations in some situations where non-emissions controllers may not be feasible at sites with power, and therefore, we are proposing to include an allowance for the use of natural gas-driven pneumatic controllers at sites with power where needed due to functional requirements in this BSER determination. 
      Use of Combustion Devices and VRUs at Production and Transmission and Storage Sites with Power (Subcategory 1). Another option that could be used to reduce emissions from pneumatic controllers is to collect the emissions from natural gas driven continuous bleed controllers and intermittent vent controllers and route the emissions through a closed vent system to a control device or process. While controls would not reduce emissions by 100 percent, this option is allowed in some state rules to satisfy the requirement that controllers are non-emitting. While we did not evaluate the cost effectiveness of this option due to a lack of available information regarding control system costs and feasibility across sites, we think this option could be cost effective for owners and operations in certain situations, and it could be appropriate to allow this as an alternative to non-emitting controllers in some cases, particularly if the site already has a control device to which the emissions from controllers could be routed. As this option could be used to achieve significant methane and VOC emission reductions (95 percent or greater), we are soliciting comment on whether we should include the use of control devices to achieve 95 or 98 percent control as an alternative to zero-emissions controllers and/or in those situations where non-emissions controllers are not technically feasible. This option would include a requirement that the control device achieve at least 95 percent reduction and that all testing and monitoring requirements associated with the use of a control device be followed. It would also require monitoring for fugitive leaks of the closed vent system that collects and routes the emissions to a control device or process. We are soliciting comment on whether routing emissions from natural gas-driven pneumatic controllers to a control device or a process should be allowed in NSPS OOOOb in any particular circumstances as an alternative to the use of other non-emitting controllers.
Natural Gas Processing Plants. 
      Natural gas processing plants typically have higher numbers of pneumatic controllers than production and transmission and storage sites. Model plants were also used for this analysis, specifically the model plants used are the same as those used for the 2011 BSER analysis, and include small, medium, and large sites. The number of controllers is 15, 63 and 175 for small, medium, and large model plants, respectively. All controllers at these sites are assumed to be continuous, but the number of low bleed and high bleed devices is not specified for the model plants. It was assumed that each controller emitted 1 tpy methane, as derived from Volume 12 of a 1996 GRI report. In addition, it was assumed that the portion of natural gas that is methane is 82.8 percent in the natural gas processing segment, and the specific VOC to methane ratio assumed was 0.278 pounds VOC per pound methane. For detailed information on the configuration of these model plants, see the TSD, which is available in the docket. 
      Using a generic emissions factor from a 1996 GRI study and assuming a representative amount of methane and VOC content in the natural gas processing segment, baseline emissions for all controllers at a natural gas processing plant were estimated to be 6.2 tpy methane and 0.2 tpy VOC.
      For natural gas processing plants, the only option evaluated was the requirement to use non-emitting controllers. For our analysis, we examined the use of instrument air, which is the most commonly used controller technology at natural gas processing plants. For this analysis, we used cost data from the 2011 NSPS TSD updated to 2019 dollars. The updated capital costs for an instrument air system at a natural gas processing plant ranges from $20,000 to $162,000, depending on the system size. The annualized costs were based on a 7 percent interest rate and a 10-year equipment life. This equated to an annualized cost of approximately $13,000 to $96,000 per system. The emissions reduction associated with the installation of an instrument air system over natural gas-driven pneumatic controllers ranged from approximately 15 to 175 tpy methane and 4.2 to 49 tpy VOC per system. The cost effectiveness is estimated to range from approximately $550 to $900 per ton methane eliminated $2,000 to $3,100 per ton VOC eliminated. When considering the costs of saving the natural gas that would otherwise be emitted, the cost effectiveness improves, with a cost effectiveness of $350 to $680 per ton of methane eliminated and $1,250 to $2,400 per ton of VOC eliminated. These cost effectiveness values are presented on a single pollutant basis, and the cost of control on a multipollutant basis is 50 percent of these values. These values are well within the range of what the EPA considers to be reasonable for methane and VOC using both the single pollutant and multipollutant approaches.
      The 2012 NSPS OOOO and 2016 NSPS OOOOa requires a zero-bleed emission rate for pneumatic controllers at natural gas processing plants. Natural gas processing plants have successfully met this standard. Further, several state agencies have rules that include this zero-bleed requirement. This is a demonstration of the reasonableness of a natural gas emission rate of zero for pneumatic controllers at natural gas processing plants. 
      We find the cost effectiveness of eliminating methane and VOC emissions using both the single pollutant and multipollutant approaches to be reasonable. 
      Secondary impacts from the use of instrument air systems are indirect, variable, and dependent on the electrical supply used to power the compressor. These impacts are expected to be minimal, and no other secondary impacts are expected.
      In light of the above, we find that the BSER for reducing methane and VOC emissions from natural gas-driven pneumatic controllers at natural gas processing plants is the use of zero-emissions controllers. Therefore, for NSPS OOOOb, we are proposing to require a natural gas emission rate of zero for all pneumatic controllers at natural gas processing plants. However, we recognize that there may be technical limitations in some situations where zero-emissions controllers may not feasible, and therefore, we are proposing an allowance for the use of natural gas-driven pneumatic controllers where needed due to functional requirements in this BSER determination. Justification of this functional need must be provided in an annual report and maintained in records.
2. EG OOOOc
      The EPA evaluated BSER for the control of methane from existing pneumatic controllers (designated facilities) in all segments in the Crude Oil and Natural Gas source category covered by the proposed NSPS OOOOb and translated the degree of emission limitation achievable through application of the BSER into a proposed presumptive standard for these facilities that essentially mirrors the proposed NSPS OOOOb.
      First, based on the same criteria and reasoning as explained above, the EPA is proposing to define the designated facilities in the context of existing pneumatic controllers as those that commenced construction on or before [INSERT DATE OF PUBLICATION IN FEDERAL REGISTER]. Based on information available to the EPA, we did not identify any factors specific to existing sources that would indicate that the EPA should these definitions as applied to existing sources. Next, the EPA finds that the controls evaluated for new sources for NSPS OOOOb are appropriate for consideration for existing sources under the EG OOOOc. The EPA finds no reason to evaluate different, or additional, control measures in the context of existing sources because the EPA is unaware of any control measures, or systems of emission reduction, for pneumatic controllers that could be used for existing sources but not for new sources. Next, the methane emission reductions expected to be achieved via application of the control measures identified above to new sources are also expected to be achieved by application of the same control measures to existing sources. The EPA finds no reason to believe that these calculations would differ for existing sources as compared to new sources because the EPA believes that the baseline emissions of an uncontrolled source are the same, or very similar, and the efficiency of the control measures are the same, or very similar, compared to the analysis above. This is also true with respect to the costs, non-air environmental impacts, energy impacts, and technical limitations discussed above for the control options identified.
      For the most part, the information presented above regarding the costs related to new sources and the NSPS are also applicable for existing sources. There are two exceptions to this, for which the EPA determined that the costs for the option for existing sources differed from the cost for new sources. The following sections discuss these differences and the BSER conclusions for the proposal for the EG under subpart OOOOc.
a. Production and Transmission and Storage Sites Without Power (Subcategory 2). 
      For existing sources, the estimated costs for the option to require low bleed controllers instead of high bleed controllers is different than discussed above for new sources. Presumably, an existing source would already have a high bleed controller in place that would need to be replaced. Therefore, the entire cost of installing a low bleed controller would be applicable (as opposed to just the difference between the cost of a low bleed versus a high bleed controller). This cost, $3,030, was used and was annualized for a 15-year period using a 7 percent interest rate. The methane emissions reductions are the same as those calculated for new sources, or 2.1 tons per year per device in the production segment and 2.9 tons per year in the transmission and storage segment per controller.
      The cost effectiveness is estimated to be $160 per ton of methane reduced in the production segment for existing sources. Considering the value of the gas saved in the production segment, the result is a net savings. For the natural gas transmission and storage segment, the cost of control is $120 per ton of methane reduced. As noted above, transmission and storage facilities do not own the natural gas; therefore, revenues from reducing the amount of natural gas emitted/lost was not estimated for this segment. 
      These costs are within the range considered to be reasonable by the EPA. Since none of the other factors are different from those discussed above for new sources, the EPA concludes that BSER for existing sources and the EG OOOOc for the subcategory of production and transmission and storage sites that do not have power to be the requirement of the use of low bleed controllers, along with a requirement that intermittent vent controllers only vent during actuation.
b. Production and Transmission and Storage Sites with Power (Subcategory 1). 
      The second instance where the EPA estimated a difference in the costs between a new and existing source was for the retrofit of an existing production site to use instrument air at sites equipped with electrical power. While the equipment needed is the same as for new sites, it may be more difficult to design and install a retrofitted system. Therefore, the EPA estimates the costs for design and installation to be twice that of the costs for new systems (from approximately $32,000 for new systems to approximately $64,000 for existing systems), resulting in the capital cost of the system being approximately $127,000 with an annualized cost of approximately $14,000. 
      As noted above, the analysis only examined the cost of instrument air for the large model plant for the subcategory of production and transmission and storage sites with power. The total elimination of methane emissions (25 tons per year methane for production sites and 10 tons per year methane for transmission and storage sites) would be the same as presented above for new sources. Considering the cost difference, the cost effectiveness for production sites is $560 per ton of methane eliminated without considering savings, and $365 per ton when considering savings. For the transmission and storage segment, the cost effectiveness is $1,400 per ton of methane eliminated. These values are well within the range of what the EPA considers to be reasonable for methane and VOC using both the single pollutant and multipollutant approaches.
      The change in costs for the low bleed option and the instrument air option for existing sources results in a change in the incremental cost effectiveness. The incremental cost effectiveness going from the low bleed to the non-emission option for the large model plant production sites with power is $400 per ton of methane eliminated. For the large model plant transmission and storage sites, this incremental cost effectiveness is $1,300 per ton of methane eliminated.
      The EPA considers these cost effectiveness values (including the incremental cost effectiveness) to be reasonable. Since none of the other factors are different from discussed above for new sources, the EPA concludes that BSER for existing sources and the EG OOOOc for the subcategory of production and transmission and storage sites that have electricity to be the requirement to use non-emitting controllers.
      The EPA recognizes there are different regulatory implementation approaches that could be followed. While the EPA is proposing to subcategorize based on availability of onsite power, another approach instead could be to establish a phase-in period for compliance with standards for sources without onsite power. The state of Colorado standards for pneumatic controllers utilize a phase-in approach for existing sources. The EPA recognizes that a phase-in approach may only be appropriate for existing sources as brand new facilities could presumably plan for non-emitting controllers during construction. A phase-in approach may potentially provide greater emissions reductions over time because sites would need to convert to having non-emitting controllers even when onsite power is not available. A phase-in period could span a number of years (e.g., 2 years), to allow owners and operators to prioritize conversion of natural gas-driven controllers at existing sites based on specific factors (e.g., focus on sites with onsite power, sites with highest production, sites with the most number of controllers). A phase-in approach would require the conversion of a certain percentage of sites within a given area (e.g., state or basin). For example, the state of Colorado requires a minimum of 40 percent of sites converted after 2 years, with 15 percent in year 1 and 25 percent in year 2. The EPA recognizes potential challenges with a phase-in approach. A phase-in period may be difficult to enforce due to the frequency at which sites may changes ownership. This can impact how the percentages for phase-in are calculated. The EPA anticipates it would be very challenging to analyze impacts without knowing the population of controllers under each requirement. The EPA solicits comment on all aspects of a phase-in approach and whether the agency should consider this type approach instead of the proposed subcategory approach. The EPA also solicits comment on cost and feasibility factors that would enter into adopting and designing a phase-in requirement. The EPA is specifically interested in the proportion of existing sites that currently lack onsite power and the cost and feasibility of either equipping those sites with grid access or adopting other non-emitting options on site.       
c. Natural Gas Processing Plants. 
      The information presented above regarding the emissions, emission reduction options and their effectiveness, costs, and other factors related to new natural gas processing plants and the NSPS are also applicable for existing sources. Therefore, the EPA concludes that BSER for existing sources and the EG OOOOc for natural gas processing plants is the requirement to use zero-emission controllers.
D. Proposed Standards for Well Liquids Unloading Operations
1. NSPS OOOOb
a. Background
      In the 2015 NSPS OOOOa proposal (80 FR 56614-56615, September 18, 2015), the EPA stated that based on available information and input received from stakeholders on the 2014 Oil and Natural Gas Sector Liquids Unloading Processes review document, sufficient information was not available to propose a standard for liquids unloading. 
      At that time, the EPA requested comment on technologies and techniques that could be applied to new gas wells to reduce emissions from liquids unloading events in the future. In the 2016 NSPS OOOOa final rule (81 FR 35846, June 3, 2016), the EPA stated that, although the EPA received valuable information from the public comment process, the information was not sufficient to finalize a national standard representing BSER for liquids unloading at that time. 
      For this proposal, the EPA conducted a review of this previous determination and re-evaluated the available information. As a result of this review, the EPA is proposing a standard under NSPS OOOOb that 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. These proposed requirements apply to each well liquids unloading event. 
	An overall description of liquids unloading, the definition of a modification, the definition of affected facility, our BSER analysis, and the proposed format of the standard are presented below.
b. Description
      In new gas wells, there is generally sufficient reservoir pressure/gas velocity to facilitate the flow of water and hydrocarbon liquids through the well head and to the separator to the surface along with produced gas. In mature gas wells, the accumulation of liquids in the wellbore can occur when the bottom well pressure/gas velocity approaches the average reservoir pressure (i.e., volumetric average fluid pressure within the reservoir across the areal extent of the reservoir boundaries). This accumulation of liquids can impede and sometimes halt gas production. When the accumulation of liquids results in the slowing or cessation of gas production (i.e., liquids loading), removal of fluids (i.e., liquids unloading) is required in order to maintain production. These gas wells therefore often need to remove or "unload" the accumulated liquids so that gas production is not inhibited.  
      The 2019 U.S. GHGI estimates almost 175,800 metric tpy of methane emissions from liquids unloading events for natural gas systems. Specifically, this includes almost 175,800 metric tpy from natural gas production, 98,900 of which is from liquids unloading events that use a plunger lift, and 76,900 from liquids unloading events that do not use a plunger lift. The overall total represents 3 percent of the total methane emissions estimated from natural gas systems. 
      In addition to the GHGI information, we also examined the information submitted under GHGRP subpart W. Specifically, we examined the GHGRP subpart W liquids unloading emissions data reported for Reporting Years 2015 to 2019. The liquids unloading emissions reported under GHGRP subpart W include emissions from venting wells, including those wells that vent during events that use a plunger lift and wells that vent during events that do not use a plunger lift. The information reported shows that methane emissions from liquids unloading for a well range from 0 to over 1,000 metric tons (1,100 tons) per year. While the single well with liquids unloading emissions of 1,100 tons per year appears to be an outlier, there were over 65 subbasins with reported average liquids unloading emissions of 50 tons per year or greater per well when disaggregating data by year and calculation method. There were over 1,000 wells reporting in these subbasins. In addition, there were almost 300 subbasins with reported average liquids unloading methane emissions of 10 tons per year or greater per well. There were almost 8,000 wells reporting in these subbasins.
      Another source of information reviewed related to emissions information from liquids unloading was a study published in 2015 by Allen, et al (University of Texas (UT) Study).[,] The UT Study collected monitoring data across regions of the U.S. Among other findings in this report, for wells that vent more than 100 times per year, the average methane emissions per well per year were 27 metric tons per year, with 95 percent confidence bounds of 10 to 50 Mg/yr (based on the confidence bounds in the emissions per event). The monitoring data shows that methane emissions from liquids unloading for a well range from 1 to 19,500 Mscf per year, or 0.02 to 406 tons per year. As indicated by the UT study emissions information, a small fraction of wells account for a large fraction of liquids unloading emissions.
c. Modification
	As noted above, new wells typically do not require liquids unloading until the point that the accumulation of liquids impedes or even stops gas production. In the absence of methods that would reduce or eliminate emissions, the well must be unloaded of liquids to improve the gas flow. One method to accomplish this involves the intentional manual venting of the well to the atmosphere to improve gas flow. This is done using various techniques. One common manual unloading technique diverts the well's flow, bypassing the production separator to an atmospheric pressure tank. Under this scenario, venting to the atmospheric tank occurs because the separator operates at a higher pressure than the atmospheric tank and the well will temporarily flow to the atmospheric tank (which has a lower pressure than the pressurized separator). Natural gas is released through the tank vent to the atmosphere until liquids are unloaded and the flow diverted back to the separator. 
	Since each unloading event constitutes a physical or operational change to the well that has the potential to increase emissions, the EPA is proposing to determine each event of liquids unloading constitutes a modification that makes a well an affected facility subject to the NSPS. See 40 CFR 60.14(a) ("any physical or operational change to an existing facility which results in an increase in the emission rate to the atmosphere of any pollutant to which a standard applies shall be considered a modification within the meaning of section 111 of the Act"). The EPA solicits comment on this determination. 
d. Definition of Affected Facility
	Given that we have proposed to determine that every liquids unloading event is a modification, the next step is to define the affected facility. The EPA recognizes that methods are commonly employed that significantly reduce, or even eliminate, emissions from liquids unloading. Therefore, the EPA is co-proposing two options on how a modified well due to a liquids unloading event would be covered under the rule. 
	Under the first option, the affected facility subject to the requirements of NSPS OOOOb would be defined as every well that undergoes liquids unloading after the effective date of the final rule. Under this scenario, a well that undergoes liquids unloading is an affected facility regardless of whether the liquids unloading approach used results in venting to the atmosphere. This option posits that techniques employed to unload liquids that do not increase emissions are not to be considered in whether the unloading event is an affected facility or not, since the liquids unloading event in their absence could result in an emissions increase. This is somewhat analogous to a physical change to an existing storage vessel that resulted in the ability to increase throughput, and thus emissions. This physical change could result in an increase in emissions even if emissions were captured and routed back to a process such that the level of pollutant actually emitted to the atmosphere did not change. Under this scenario, the EPA could request and obtain compliance and enforcement information on non-venting liquids unloading event methods commonly employed (simple records and reporting requirements), as well as venting liquids unloading events. 
	Under the second option, the affected facility would be defined as every well that undergoes liquids unloading using a method that is not designed to totally eliminate venting (i.e., that results in emissions to the atmosphere). Under this scenario, if an owner or operator employs a method to unload liquids that does not vent to the atmosphere, the liquids unloading event would not constitute an increase in emissions and therefore, the well would not be an affected facility. As such, the first liquids unloading event that vents to the atmosphere after the effective date of the final rule, would be an affected facility subject to the requirements of NSPS OOOOb. This option could create an enforcement information and compliance gap. Specifically, the EPA would not be able to obtain compliance assurance information on liquids unloading events and emissions/methods and there could be a decreased incentive for owners or operators to ensure that no unexpected emission episodes occur when a method designed to be non-venting is used. 
	The EPA solicits comments on the two affected facility definition options being co-proposed. Specifically, we request comment on whether there are implementation and/or compliance assurance concerns that arise with applying either of the co-proposed options. In addition, we request comment on if there are any appropriate exemptions for operations that may be unlikely to result in emissions, such as wellheads that are not operating under positive pressure.  
e. BSER Analysis
	The choice of what liquids unloading technique to employ is based on an operator well-by-well and reservoir-by-reservoir engineering analysis. Because liquids unloading operations entail a number of complex science and engineering considerations that can vary across well sites, there is no single technological solution or technique that is optimal for liquids unloading at all wells. Rather, a large number of differing technologies, techniques and practices (i.e., "methods") have been developed to address the unique characteristics of individual wells so as to manage liquids and maintain production. These methods include, but are not limited to, 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. 
	Selecting a particular method to meet a particular well's unloading needs must be based on a production engineering decision that is designed to remove the barriers to production. The situation is further complicated as the best method for a particular well can change over time. At the onset of liquids loading, techniques that rely on the reservoir energy are typically used. Eventually a well's reservoir energy is not sufficient to remove the liquids from the well and it is necessary to add energy to the well to continue production. 
	In the 2016 NSPS OOOOa final rule preamble, the EPA acknowledged that operators must select the technique to perform liquids unloading operations based on the conditions of the well each time production is impaired. During the development of the 2016 NSPS OOOOa rule, the EPA considered subcategorization based on the potential for well site liquids unloading emissions but determined that the differences in liquids unloading events (with respect to both frequency and emissions level) are due to specific conditions of a given well at the time the operator determines that well production is impaired such that unloading must be done. Since owners and operators must select the technique to perform an unloading operation based on those conditions, and because well conditions change over time, each iteration of unloading may require repeating a single technique or attempting a different technique that may not have been appropriate under prior conditions. As noted above, we recognized that the choice of method to unload liquids from a well needs to be a production engineering decision based on the characteristics of the well at the time of the unloading, and owners and operators need the flexibility to select a method that is effective and can be safely employed. No information has become available since 2016 that leads the EPA to reach a different conclusion regarding subcategorization of wells for the purpose of developing standards to address liquids unloading emissions. Further, the EPA acknowledges the need for owners and operators to have the flexibility to select the most appropriate method(s) and recognize that any standard must not impede this flexibility.
	Many methods used for liquids unloading do not result in any venting to the atmosphere, provided that the method is properly executed. High-level summaries of a few of these methods are provided below. 
	A commonly used method employed in the field is the use of a plunger lift system. While plunger lift systems often are used in a way to minimize emissions, under certain conditions they can be operated to unload liquids in a manner that eliminates the need to vent to the atmosphere. Plunger lifts use the well's own energy (gas/pressure) to drive a piston or plunger that travels the length of the tubing in order to push accumulated liquids in the tubing to the surface. Specific criteria regarding well pressure and liquid to gas ratio can affect applicability. Candidate wells for plunger lift systems generally do not have adequate downhole pressure for the well to flow freely into a gas gathering system. Optimized plunger lift systems (e.g., with smart well automation) can decrease the amount of gas vented by up to and greater than 90 percent, and in some instances can reduce the need for venting due to overloading. Plunger lift costs range from $1,900 to $20,000. Adding smart automation can cost anywhere between an estimated $4,700 to $18,000 depending on the complexity of the well. Natural Gas STAR estimates that the annual cost savings from avoided emissions from the use of an automated system ranges anywhere between $2,400 and $10,241 per year.
      Other artificial lifts (e.g., rod pumps, beam lift pumps, pumpjacks and downhole separator pumps) are typically used when there is inadequate pressure to use a plunger lift, and the only means of liquids unloading to keep gas flowing is downhole pump technology. Artificial lifts can be operated in a manner that produces no emissions. The use of an artificial lift requires access to a power source. The capital and installation costs (including location preparation, well clean out, artificial lift equipment and pumping unit) is estimated to be $41,000 to $62,000/well, with the average cost of a pumping unit being between $17,000 to $27,000.  
	Velocity tubing is smaller diameter production tubing that reduces the cross-sectional area of flow, increasing the flow velocity and achieving liquids removal without blowing emissions to the atmosphere. Generally, a gas flow velocity of 1,000 feet per minute (fpm) is necessary to remove wellbore liquids. Velocity tubing strings are appropriate for low volume natural gas wells upon initial completion or near the end of their productive lives with relatively small liquids production and higher reservoir pressure. Candidate wells include marginal gas wells producing less than 60 Mcfd. Similarly, coil tubing can also be used in wells with lower velocity gas production (i.e., seamed coiled tubing may provide better lift due to elimination of turbulence in the flow stream). The proper use of velocity tubing is considered to be a "no emissions" solution. It is also low maintenance and effective for low volumes lifted. Velocity lifting can be deployed in combination with foaming agents (discussed below). The capital and installation costs are estimated to range anywhere from $7,000 to $64,000 per well. Installation requires a well workover rig to remove existing production tubing and placement of the smaller diameter tubing string in the well.
	The use of foaming agents (soap, surfactants) as a method to unload liquids is implemented by the injection of foaming agents in the casing/tubing annulus by a chemical pump on a timer basis. The gas bubbling of the soap-water solution creates gas-water foam which is more easily lifted to the surface for water removal. This, like the use of artificial lifts, requires power to run the surface injection pump. Additionally, foaming agents work best if the fluid in the well is at least 50 percent water and are not effective for natural gas liquids or liquid hydrocarbons. This method requires that the soap supply be monitored. If the well is still unable to unload fluid, smaller tubing may be needed to help lift the fluids. Foaming agents and velocity tubing are reported as possibly being more effective when used in combination. No equipment is required in shallow wells. In deep wells, a surfactant injection system requires the installation of surface equipment and regular monitoring. Foaming agents are reported as being low cost "no emissions" solution. The capital and startup costs to install soap launchers and velocity tubing is estimated to range between $7,500 and $67,880, with the monthly cost of the foaming agent is approximately $500 per well or approximately $6,000 per year. 
	These are just a few examples of demonstrated methods that are being used to in the industry to unload accumulated liquids that impair production, that can be implemented to eliminate venting and thus, emissions. As stressed earlier, the selection of a specific method must be made based on well-specific characteristics and conditions.
	Since GHGRP subpart W only requires reporting of liquids unloading events that resulted in venting of methane, no information is submitted regarding those wells that utilize a non-venting method. The EPA is also not aware of information that specifies the total number of wells that need to undergo liquids unloading. A 2012 report sponsored by the API and American Natural Gas Alliance (ANGA) provided more definitive insight into the number of wells that use non-venting liquids unloading methods. This report indicated that an estimated 21.1 percent of plunger equipped wells vent, and 9.3 percent of non-plunger equipped wells vent. The EPA interprets this to mean that almost 80 percent of plunger-equipped wells, and over 90 percent of non-plunger-equipped wells perform liquids unloading and utilize non-venting methods.
	As noted above, there is a tremendous range in the emissions from liquids unloading reported for individual wells. Further, as discussed above, the costs for the non-venting methods range considerably. Also as discussed above, we have determined that the myriad of possible reservoir conditions and unloading methods do not lend to any reasonable subcategorization of the industry for which representative wells could be designed. Therefore, it is not possible to develop a "model" well, or even a series of model wells, that can be used to conduct the type of analysis frequently performed for BSER determinations that calculates a cost per ton of emissions reduced (or in this case eliminated). 
	Based on the highest costs included in the cost examples provided above, the cost effectiveness of a non-emitting method would be considered reasonable for all wells with annual methane emissions from liquids unloading of 16 tpy or greater, or VOC emissions of 3 tpy or greater. This upper range is based on the cost of the combination of velocity tubing and soap launchers. The upper range of the capital cost cited above was $67,800. Annualizing this capital cost at a 7 percent interest rate over 10 years, and adding in the $6,000 per year foaming agent cost, results in a total annual cost of $15,600. Given the total elimination of emissions, the cost effectiveness for a well with 16 tpy methane emissions would be $980 per ton of methane reduced, which is a level that the EPA considers reasonable for methane. Similarly, for VOC, the cost effectiveness for a well with 3 tpy VOC emissions would be $5,200 per ton of VOC reduced. This is also a level that the EPA considers reasonable. Given the range of costs, it could be considered reasonable for some wells (in instances where the costs of the technique employed are lower for a particular well unloading operation) with annual liquids unloading methane emissions as low as 2.5 tpy, or VOC emissions as low as 0.2 tpy. Based on the GHGRP subpart W data for the years 2015 through 2019, around 50 percent of the wells that performed liquids unloading and reported emissions reported emissions higher than these levels. 
	As discussed above, 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 below). It is possible that many of the wells reporting lower emissions have already explored non-emitting options and determined that there was no feasible option. In these cases, they would not be required to implement a non-emitting method that may not be cost effective for that particular well.
	In summary while owners and operators must select a liquids unloading method that is applicable for the well-specific conditions, they have the choice of many methods that can be used to eliminate venting/emissions from liquids unloading events. While we do not have information to calculate the specific percentage of total wells undergoing liquids unloading that use non venting methods, available information suggests that a majority of wells that undergo liquids unloading do not vent. The EPA solicits information on the number (or percent) of liquids unloading events that vent to the atmosphere versus do not vent to the atmosphere under normal conditions and whether there are technical obstacles (other than costs) that would not allow liquids unloading to be performed without venting. 
	The complete elimination of emissions from liquids unloading, which is adequately demonstrated, clearly represents the "best" emission reduction available. It is acknowledged that as part of decisions regarding liquids unloading, one goal of owners and operators is to eliminate venting to prevent the loss of product (natural gas) that could be routed to the sales line. States currently encourage the use of methods to eliminate emissions unless venting of emissions is necessary for safety reasons or when it is technically infeasible to not vent to unload liquids from the wellbore. For example, Pennsylvania has a general plan approval and/or general operating permit application (BAQ-GPA/GP-5A) that specifies that an owner or operator that conducts wellbore liquids unloading operations shall use best management practices including, but not limited to, plunger lift systems, soaping, swabbing, unless venting is necessary for safety to mitigate emissions during liquids unloading activities (Best Available Technology (BAT) Compliance Requirements under Section L of the General Permit).
	As discussed previously, a large percentage of wells already conduct liquids unloading operations without venting to the atmosphere. The significant number of wells that perform liquids unloading without venting is a demonstration that non venting methods are reasonable. The EPA believes that the large number of wells that employ non-venting methods likely represent most, if not all, of the well-specific conditions that an owner or operator may face in selecting an unloading operation. This means that the potential exists that a non-emitting method is available for all wells. In addition, our evaluation of costs shows that there are methods that could be employed to unload liquids that are reasonable given a wide range of emission levels. This means it is feasible that there is a cost-effective option available for all wells. Finally, there are no negative secondary impacts that would result from the implementation of methods that would eliminate venting of methane and VOC emissions to the atmosphere. In light of the above, we determined that eliminating venting from a liquids unloading event represents BSER for NSPS OOOOb for this proposal. 
	Although the EPA has determined that BSER for liquids unloading events is that methods be employed that are non-venting/zero-emitting, the EPA also recognizes that there may be safety and technical reasons why venting to the atmosphere is necessary to unload liquids. For scenarios where a liquids unloading method employed requires venting to the atmosphere, the EPA evaluated requiring BMPs that would minimize venting to the maximum extent possible. There are several states that require the development and implementation of BMPs that minimize emissions from liquids unloading events that vent. For example, Colorado requires specified BMPs to eliminate or minimize vented emissions from liquids unloading. The rule requires that all attempts be made to unload liquids without venting unless venting is required for safety reasons. If venting is required, the rule requires that owners and operators be on site and that they ensure that any venting is limited to the maximum extent practicable.  Specific BMPs evaluated are based on state rules that require BMPs to minimize emissions during liquids unloading events are to require operators to monitor manual liquids unloading events onsite and to follow procedures that minimize the need to vent emissions during an event. This includes 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 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 results 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. We performed a cost and impacts evaluation of the use of BMPs to reduce emissions from liquids unloading. This evaluation is provided in the Technical Support Document for this rulemaking.
	Another potential method for reducing emissions from liquids unloading is to capture the vented gas from an unloading event and route it to a control device. At the time the Crude Oil and Natural Gas Sector Liquids Unloading Processes draft review document was submitted to reviewers, the EPA noted that, although the EPA was not aware of any specific instances where combustion devices/flares were used to control emissions vented from unloading events, the EPA requested information on the technical feasibility of flaring as an emissions control option for liquids unloading events. Feedback received from reviewers indicated that there are technical reasons that flaring during liquids unloading is not a feasible option. Reviewers emphasized that, in order to flare gas during liquids unloading, the liquids would need to be separated from the well stream, and the intermittent and surging flow characteristics of venting for liquids unloading, changing velocities during an unloading, and flare ignition considerations for a sporadically used flare (i.e., would require either a continuous pilot or electronic igniter) would make use of a flare technically and financially infeasible. [,] The reviewers indicated that separating the liquids from the well stream would require the well stream to flow through a separator with sufficient backpressure to separate the gas and liquids. One reviewer noted that after separating the liquids from the well stream the gas would then be piped to flare system, where the backpressure needed to operate the separator would affect the performance of a plunger lift system (if used). Based on feedback received on the technical and cost feasibility of using a flare to control vented emissions from liquids unloading events indicating that a flare cannot be used in all situations, we did not consider this option any further as BSER in this proposal. However, the EPA is soliciting comments about the use of control devices to reduce emissions from liquids unloading events. Specifically, we would request information on the types of wells and unloading events for which routing to control is feasible and effective, the level of emission reduction achieved, and the testing and monitoring requirements that apply.
	A similar potential method is to capture the vented gas from an unloading event and route it to the sales line or back to a process. This could potentially represent another method that results in zero emissions. While this is not a mitigation option that has been specifically mentioned for emissions from liquids unloading, it is a common option for other emission sources in the oil and natural production segment. The EPA is soliciting comments about the option to collect and route emissions back to the sales line or to a process. Specifically, we request information on the types of wells and unloading events for which this option is feasible (if any). If it is feasible, we would also request information on the specifics of the equipment and processes needed to accomplish this, as well as the costs. In conclusion, the EPA evaluated several options for eliminating methane and VOC emissions from liquids unloading events. The conclusions are that BSER is the use of a non-venting/non emitting method for liquids unloading. However, the EPA recognizes there could be situations where it is infeasible to utilize a zero-venting method. Therefore, the EPA concludes that the rule must allow for the development and implementation of BMPs to reduce emissions to the extent possible during liquids unloading where it is infeasible to utilize a zero-emitting venting method.
f. Format of the Standard
      As discussed under section XII.D.1.d of this preamble, the EPA is co-proposing two regulatory approaches to implement the BSER determination.
      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 they (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; (3) follow the BMPs during each liquids unloading and maintain records demonstrating they were followed; (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 the specific practices that must be included, it would specify the types and nature of the practices. Examples of the types and nature of the required practice elements are provided above (see section XII.D.1.e), such as those contained in Colorado's rule. The EPA is specifically requesting comment on the minimum elements that should be required in BMPs and the specificity that the proposed rule should include regarding these elements.
      An advantage of this regulatory option is that it would provide information to the EPA on the number of liquids unloading events that occur and the types of unloading methods used. As discussed previously, the EPA is not aware of comprehensive information on the number of wells that utilize non-venting liquids unloading methods. This method would provide important information to continue to enhance the EPA, the industry, and the public's knowledge of emissions from liquids unloading. In addition, it would also provide incentive for owners and operators to ensure that non-venting methods are applied as they are designed such that unexpected emissions do not occur as the result of technology malfunctions or operator error. However, it would result in some recordkeeping and reporting burden for wells using non-venting methods that would not be incurred under Option 2.
      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 demonstrate that they did not use non-venting methods and were not subject to NSPS OOOOb. The requirements for wells that use methods that vent would be the same as described above under Option 1. 
      The EPA believes that this option would provide additional incentive for owners and operators to seek ways to overcome potential infeasibility issues to ensure that their wells are not affected facilities and subject to reporting and recordkeeping requirements. This would ultimately result in lower emissions. However, this would not provide the EPA information to enable a comprehensive understanding of emissions and emission reduction methods from liquids unloading. It would also not provide incentive for owners and operators to ensure that no unexpected emission episodes occur when a method designed to be non-venting is used.
2. EG OOOOc
      As described above, the EPA is proposing that each unloading event represents a modification, which will make the well subject to new source standards under NSPS. Therefore,  existing wells that undergo liquids unloading would become subject to NSPS OOOOb. This will mean that there will never be a well that undergoes liquids unloading that will be "existing" for purposes of CAA section 111(d). Therefore, there is no need for emissions guidelines or an associated presumptive standard under the subpart OOOOc for liquids unloading operations.
E. Proposed Standards for Reciprocating Compressors
1. NSPS OOOOb
a. Background
      The 2012 NSPS OOOO and the 2016 NSPS OOOOa applied to each individual new or reconstructed reciprocating compressor, except for those compressors located at a well site, or those located at an adjacent well site and servicing more than one well site. The 2016 NSPS OOOOa required the reduction of methane and VOC emissions from new, reconstructed, or modified reciprocating compressors by replacing rod packing systems within 26,000 hours or 36 months of operation, regardless of the condition of the rod packing. As an alternative, the 2016 NSPS OOOOa allowed owners or operators to collect the emissions from the rod packing using a rod packing emissions collection system that operates under negative pressure and route the rod packing emissions to a process through a closed vent system.
	In determining BSER for reciprocating compressors in 2016, the EPA determined that the previous determination for NSPS OOOO conducted in 2011/2012 still represented BSER in 2016. In the 2012 determination the EPA first concluded that the piston rod packing wear produces fugitive emissions that cannot be captured and conveyed to a control device, and that an operational standard pursuant to section 111(h) of the CAA was appropriate. The EPA conducted analyses of the costs and emission reductions of the replacement of rod packing every 3 years or 26,000 hours of operation and determined that the costs per ton of emissions reduced were reasonable for the industry, with the exception of compressors at well sites. Based on the 2011 BSER analysis, requiring replacement of rod packing every 3 years or 26,000 hours of operation for well site reciprocating compressors was not considered cost effective (almost $57,000 per ton of VOC reduced). No other more stringent control options were evaluated at that time. 
	For this review of the NSPS, the EPA focused on these control options which were previously assessed for the 2012 NSPS OOOO and the 2016 NSPS OOOOa. In addition, we evaluated an option that would require annual monitoring to determine if the rod packing needed to be replaced. This option is in contrast to the option where replacement is required on a fixed (e.g., 3 year) schedule. For this review, BSER was evaluated for reciprocating compressors at gathering and boosting stations in the production segment (considered to be representative of emissions from reciprocating compressors at centralized production facilities), at natural gas processing plants, and at sites in the transmission and storage segment. In 2012 and in 2016, the EPA determined that the cost effectiveness of replacement of the rod packing based on the fixed 3-year (or 26,000 hours) schedule was unreasonable for reciprocating compressors located at the well site (discussed below). No new information has become available to change this determination. Therefore, we did not include reciprocating compressors located at well sites in our evaluation of regulatory options.
	However, as discussed in section XI.K (Centralized Production Facilities) of this preamble, the EPA believes the definition of "well site" in NSPS OOOOa may cause confusion regarding whether reciprocating compressors located at centralized production facilities are also exempt from the standards. The EPA is proposing a new definition for a "centralized production facility". The EPA is proposing to define centralized production facilities separately from well sites because the number and size of equipment, particularly reciprocating and centrifugal compressors, is larger than standalone well sites which would not be included in the proposed definition of "centralized production facilities". This proposal is necessary in the context of reciprocating compressors to distinguish between these compressors at centralized production facilities where the EPA has determined that the standard should apply, and compressors at standalone well sites where the EPA has determined that the standard should not apply. In our current analysis, described below, we consider the reciprocating compressor gathering and boosting segment emission factor as being representative of reciprocating compressor emissions located at centralized production facilities. As such, the EPA is proposing that reciprocating compressors located at centralized production facilities would be subject to the standards in NSPS OOOOb and the EG in OOOOc, but reciprocating compressors at well sites (standalone well sites) would not.
	As a result of the EPA's review of NSPS OOOOa, we are proposing that BSER is to replace the rod packing when, based on annual flow rate measurements, there are indications that the rod packing is beginning to wear to the point where there is an increased rate of natural gas escaping around the packing to unacceptable levels. We are proposing that if annual flow rate monitoring indicates a flow rate for any individual cylinder as exceeding 2 scfm, an owner or operator would be required to replace the rod packing. 
b. Description
	In a reciprocating compressor, natural gas enters the suction manifold, and then flows into a compression cylinder where it is compressed by a piston driven in a reciprocating motion by the crankshaft powered by an internal combustion engine. Emissions occur when natural gas leaks around the piston rod when pressurized natural gas is in the cylinder. The compressor rod packing system consists of a series of flexible rings that create a seal around the piston rod to prevent gas from escaping between the rod and the inboard cylinder head. However, over time, during operation of the compressor, the rings become worn and the packaging system needs to be replaced to prevent excessive leaking from the compression cylinder. 
	As discussed previously, emissions from a reciprocating compressor occur when, over time, during operation of the compressor, the rings that form a seal around the piston rod that prevents gas from escaping become worn. This results in increasing emissions from the compression cylinder. Based on the 2021 GHGI, the methane emissions from compressors (both reciprocating and centrifugal compressors) in 2019 represented 14 percent of the total methane emissions from natural gas systems in the Crude Oil and Natural Gas Industry sector. For combined centrifugal and reciprocating compressors emissions, the GHGI estimated emissions are 67,000 metric tons for the production segment, and 309,500 metric tons for gathering and boosting. For segments where the GHGI included a breakdown of methane emissions for reciprocating compressors, the reported emissions were 46,700 metric tons for the processing segment, 406,500 metric tons for the transmission segment, and 103,200 metric tons for the storage segment.
c. Affected Facility
	For purposes of the NSPS, the reciprocating compressor affected facility is a single reciprocating compressor. A reciprocating compressor located at a well site, or an adjacent well site and servicing more than one well site, is not an affected facility under the proposed rule for the NSPS OOOOb. As discussed above, the EPA is proposing that the affected facility includes reciprocating compressors located at centralized production facilities and the affected facility exception for "a well site, or an adjacent well site servicing more than one well site" applies to standalone well sites and not centralized production facilities. 
d. BSER Analysis
	The methodology used for estimating emissions from reciprocating compressor rod packing is consistent with the methodology developed for the 2012 NSPS OOOO BSER analysis and then also used to support the 2016 NSPS OOOOa BSER. This approach uses volumetric methane emission factors referenced in the EPA/GRI study as the basis, multiplied by the density of methane. These factors were per cylinder, so they were multiplied by the average number of cylinders per reciprocating compressor at each oil and gas industry segment, the pressurized factor (percentage of hours per year the compressor was pressurized), and 8,760 hours (number of hours in a year). Once the methane emissions were calculated, VOC emissions were calculated by multiplying the methane by ratios developed based on representative gas composition. The specific ratios that were used for this analysis were 0.278 pounds VOC per pound of methane for the production and processing segments, and 0.0277 pounds VOC per pound of methane for the transmission and storage segment. The resulting baseline emissions from reciprocating compressors were 12.3 tpy methane (3.4 tpy VOC) from gathering and boosting stations, 23.3 tpy methane (6.5 tpy VOC) from natural gas processing plants, 27.1 tpy methane (0.75 tpy VOC) from transmission stations, and 28.2 tpy methane (0.78 tpy VOC) from storage facilities.
      Reducing emissions that result from the leaking of natural gas past the piston rod packing can be accomplished through several approaches including (1) specifying a frequency for the replacement of the compressor rod packing, (2) monitoring the emissions from the compressor and replacing the rod packing when the results exceed a specified threshold, (3) specifying a frequency for the replacement of the piston rod, (4) requiring the use of specific rod packing materials, and/or (5) capturing the leaking gas and routing it either to a process or a control device.
      There was either insufficient information to establish BSER or it was determined that the option cannot be applied in all situations for approach options (3) through (5). These are discussed briefly below.
	Like the packing rings, piston rods on reciprocating compressors also deteriorate. Piston rods, however, wear more slowly than packing rings, having a life of about 10 years.  Rods wear "out-of-round" or taper when poorly aligned, which affects the fit of packing rings against the shaft (and therefore the tightness of the seal) and the rate of ring wear. An out-of-round shaft not only seals poorly, allowing more leakage, but also causes uneven wear on the seals, thereby shortening the life of the piston rod and the packing seal. Replacing or upgrading the rod can reduce reciprocating compressor rod packing emissions. Also, upgrading piston rods by coating them with tungsten carbide or chrome reduces wear over the life of the rod. We assume that operators will choose, at their discretion, when to replace/realign or retrofit the rod as part of regular maintenance procedures and replace the rod when appropriate when the compressor is out of service for other maintenance such as rod packing replacement. Although replacing/realigning or retrofitting the rod has been identified as a potential methane and VOC emission reduction option for reciprocating compressors, there is insufficient information on its emission reduction potential and use throughout the industry. Therefore, we did not evaluate this option any further as BSER for this proposal.
	Although specific analyses have not been conducted, there may be potential for reducing methane and VOC emissions by updating rod packing components made from newer materials, which can help improve the life and performance of the rod packing system. One option is to replace the bronze metallic rod packing rings with longer lasting carbon-impregnated Teflon rings. Compressor rods can also be coated with chrome or tungsten carbide to reduce wear and extend the life of the piston rod. Although changing the rod packing material has been identified as a potential methane and VOC emission reduction option for reciprocating compressors, there is insufficient information on its emission reduction potential and use throughout the industry. Therefore, we did not evaluate this option any further as BSER for this proposal.
	The 2016 NSPS OOOOa includes the alternative to route the emissions from reciprocating compressors to a process. One estimate obtained by the EPA states that a gas recovery system can result in the elimination of over 99 percent of methane emissions that would otherwise occur from the venting of the emissions from the compressor rod packing. The emissions that would have been vented are combusted in the compressor engine to generate power. It was estimated that, if a facility is able to route rod packing vents to a VRU system, it is possible to recover approximately 95-100 percent of emissions. As a comparison, the EPA estimated that the 3-year/26,000-hour changeout results in between 55 and 80 percent emission reduction. Therefore, an option to achieve additional emission reductions could be to require routing the reciprocating compressor emissions to a process/through a closed vent system under negative pressure. Although this was a control option considered in the 2016 NSPS OOOOa (and included as an alternative), the EPA did not require routing to a process for all compressors because at that time there was insufficient information to require this as a control for all reciprocating compressors. The EPA received feedback that this option cannot be applied in every installation, and has not received any new information that indicates this has changed. Thus, this option was not considered further as a requirement but for this proposal, as with the 2016 NSPS OOOOa, it is considered to be an acceptable alternative to mitigate methane and VOC emissions where it is technically feasible to apply.
	Similarly, another option evaluated as having the potential to achieve methane and VOC emission reductions was to require the collection of emissions in a closed vent system and routing them to a flare or other control device. If the gas is routed to a flare, approximately 95 percent of the methane and VOC would be reduced. The EPA has expressed historically and maintains that combustion is not believed to be a technically feasible control option for reciprocating compressors because, as detailed in the 2011 NSPS TSD, routing of emissions to a control device can cause positive back pressure on the packing, which can cause safety issues due to gas backing up in the distance piece area and engine crankcase in some designs. The EPA has not identified any new information to indicate that this has changed. Therefore, this option was not considered further as BSER for this proposal.
	The remaining two control option approaches that were evaluated further for this proposal include: (1) specifying a frequency for the replacement of the compressor rod packing (equivalent to the frequency used in the 2016 NSPS OOOOa BSER control level), and (2) monitoring the emissions from the compressor and replacing the rod packing when the results exceed a specified threshold. Both of these approaches would reduce the escape of natural gas from the piston rod. No wastes would be created (other than the worn packing that is being replaced) and no wastewater would be generated. 
	As noted previously, periodically replacing the packing rings ensures the correct fit is maintained between packing rings and the rod, thereby limiting emissions occurring around the flexible rings that fit around the shaft by recreating a seal against leakage that may have been lost due to wear.[ ]The potential emission reductions for reciprocating compressors at gathering and boosting stations, processing plants, and transmission and storage facilities were calculated by comparing the average rod packing emissions with the average emissions from newly installed and worn-in rod packing. As noted above, because the EPA concluded that the cost effectiveness of this option was extremely unreasonable for reciprocating compressors at well sites in previous BSER analyses (see the 2011 NSPS TSD, section 2.2; 80 FR 56620, September 18, 2015), and since no new information was identified that would change this outcome as it relates to stand alone well sites, reductions and costs were not re-evaluated in this analysis for reciprocating compressors at production well sites.  
	The emissions after the replacement of the rod packing were calculated using the methodology used under previous NSPS actions (see 2021 NSPS TSD, section 7.1). The resulting emissions reductions used for the analysis represented the emission reductions expected in the year the rod packing is replaced. It is expected that there would be an increase in the emissions (and decrease in the emission reductions) from a compressor where the rod packing was replaced the second and third years before the next replacement. As noted above, this assumed reduction was between 55 and 80 percent depending on the location of the compressor.
	The costs of replacing rod packing were obtained from a Natural Gas STAR Lessons Learned document[ ]and the dollars were converted to 2019 dollars. The estimated cost to replace the packing rings in 2019 dollars was estimated to be $1,920 per cylinder. It was assumed that rod packing replacement would occur during planned shutdowns and maintenance, and therefore no additional travel costs would be incurred for implementing a rod packing replacement program. Since the assumed number of cylinders differs for reciprocating compressors at different segments, this means the capital costs also vary. These estimated capital costs are $6,350 at gathering and boosting and transmission stations, $4,800 at processing plants, and $8,650 at storage stations.
	The 26,000-hour replacement frequency used for the cost impacts in the 2011 NSPS OOOO TSD and 2016 NSPS OOOOa TSD was determined using a weighted average of the annual percentage of time that reciprocating compressors are pressurized. The weighted average percentage was calculated to be 98.9 percent. This percentage was multiplied by the total number of hours in 3 years to obtain a value of 26,000 hours. This calculates to an average of 3.8 years for gathering and boosting compressors, 3.3 years for processing compressors, 3.8 years for transmission compressors, and 4.4 years for storage compressors. The calculated years were assumed to be the equipment life of the compressor rod packing and were used to calculate the capital recovery factor for each of the segments. Assuming an interest rate of 7 percent, the capital recovery factors were calculated to be 0.3093, 0.3498, 0.3093, and 0.2695 for the gathering and boosting part of production, processing, transmission, and storage segments, respectively. 
	The capital costs were calculated using the average rod packing cost noted above and the average number of cylinders per compressor (which differs depending on sector segment).  The annual capital costs were calculated using the capital costs and the capital recovery factors. The estimated annual costs ranged from $1,700 at processing plants to just over $2,300 at storage facilities. Note that these estimated costs represent the costs, and associated emission reductions, that would occur in the year when the rod packing was changed. There would be no costs for the other two years in the three-year cycle. The costs presented for gathering and boosting segment reciprocating compressors represent the estimated costs assumed for reciprocating compressors located at centralized production facilities.
	There are monetary savings associated with the amount of natural gas saved with reciprocating compressor rod packing replacement. Monetary savings associated with the amount of gas saved with reciprocating compressor rod packing replacement were estimated using a natural gas price of $3.13 per Mcf. Estimated savings were only applied for gathering and boosting stations and processing plants, as it is assumed the owners of the compressor station do not own the natural gas that is compressed at the station. 
	Using the single pollutant approach, where all the costs are assigned to the reduction of one pollutant, the cost effectiveness of replacement of the reciprocating rod packing within 26,000 hours or 36 months of operation, regardless of the condition of the rod packing, is approximately $290 per ton of methane reduced for gathering and boosting ($100 per ton if gas savings are considered), $90 per ton of methane reduced for the processing segment (net savings if gas savings are considered), $90 per ton of methane reduced for the transmission segment, and $110 per ton of methane reduced for the storage segment. Using the multipollutant approach, where half the cost of control is assigned to the methane reduction and half to the VOC reduction, the cost effectiveness of replacement of the reciprocating rod packing within 26,000 hours or 36 months of operation, regardless of the condition of the rod packing, is approximately $140 per ton of methane reduced for gathering and boosting ($50 per ton if gas savings are considered), $45 per ton of methane reduced for the processing segment (net savings if gas savings are considered), $45 per ton of methane reduced for the transmission segment, and $50 per ton of methane reduced for the storage segment.
	Using the single pollutant approach, where all the costs are assigned to the reduction of one pollutant, the VOC cost effectiveness of replacement of the reciprocating rod packing within 26,000 hours or 36 months of operation, regardless of the condition of the rod packing, is approximately $1,030 per ton of VOC reduced for gathering and boosting ($380 per ton if gas savings are considered), $330 per ton of VOC reduced for the processing segment, $3,270 per ton of VOC reduced for the transmission segment (net savings if gas savings are considered), and $3,860 per ton of VOC reduced for the storage segment. Using the multipollutant approach, where half the cost of control is assigned to the methane reduction and half to the VOC reduction, the cost effectiveness of replacement of the reciprocating rod packing within 26,000 hours or 36 months of operation, regardless of the condition of the rod packing, is approximately $520 per ton of VOC reduced for gathering and boosting ($190 per ton if gas savings are considered), $160 per ton of VOC reduced for the processing segment (net savings if gas savings are considered), $1,630 per ton of VOC reduced for the transmission segment, and $1,930 per ton of VOC reduced for the storage segment.
	As an alternative to replacing the rod packing on a fixed schedule, another option is to replace the rod packing when, based on measurements, there are indications that the rod packing is beginning to wear to the point where there is an increased rate of natural gas escaping around the packing to unacceptable levels. This is an approach required by the California Greenhouse Gas Emission Regulation and in Canada. The California Greenhous Gas Emission Regulation requires that the rod packing/seal is to be tested during periodic inspections and, if the rod packing/seal leak concentration exceeds the specified threshold of 2 scfm/cylinder, repairs must be made within 30 days. Similarly, certain Canadian jurisdictions require periodic monitoring measurements of rod packing vent volumes (typically annually) for existing reciprocating compressors. Where specified vent volumes are exceeded, the rules require corrective action be taken to reduce the flow rate to below or equal to a specified limit, as demonstrated by a remeasurement. Vent volume thresholds specified that would result in the need for corrective action vary from 0.49 to 0.81 scfm/cylinder.
	This approach is similar to an approach identified in the Natural Gas STAR Program referred to as "Economic Packing and Piston Rod Replacement." Under this approach, facilities use specific financial objectives and monitoring data to determine emission levels at which it is cost effective to replace rings and rods. Benefits of calculating and utilizing this "economic replacement threshold" include methane and VOC emission reductions and natural gas cost savings. Using this approach, one Natural Gas STAR partner reportedly achieved savings of over $233,000 annually at 2006 gas prices. An economic replacement threshold approach can also result in operational benefits, including a longer life for existing equipment, improvements in operating efficiencies, and long-term savings. The EPA is not proposing to establish a financial objective or economic replacement threshold in this proposal, but the costs and emission reductions of replacing rod packing based on monitoring from this program were considered in the analysis discussed below.
	The elements of such a program include establishing a frequency of monitoring, identifying a threshold where action is required to reduce emissions, and specifying the action for reducing emissions. The option defined by the EPA and evaluated below is for annual monitoring and requiring the replacement of the rod packing if the measured flow rate for any individual cylinder exceeds 2 scfm. This threshold is consistent with California's regulation. However, this option differs from the California regulation in that it would require a complete replacement of the rod packing if this threshold was exceeded, where California allows repair sufficient to reduce the flow rate back below 2 scfm. The 2 scfm flow rate threshold was established based on manufacturer guidelines indicating that a flow rate of 2 scfm or greater was considered indicative of rod packing failure.   
	We estimated the emission reductions from requiring annual flow rate monitoring and repair/replacement of packing when the measured flow rate exceeds 2 scfm total gas during pressurized operation. Based on California's background regulatory documentation, information provided to the state indicated that the average leak rate for those compressors emitting more than 2 scfm was about 3 scfm during pressurized operation, and less than 2 scfm during pressurized idle and unpressurized states. Therefore, we assumed that the leak rate for compressors emitting more than 2 scfm was about 3 scfm during pressurized operation. As indicated above for the fixed schedule rod packing replacement option, based on the 2011 NSPS OOOO TSD and 2016 NSPS OOOOa TSD, the average emissions from a newly installed rod packing are assumed to be 11.5 scfh per cylinder. Using a ratio of 0.829 methane: total natural gas ratio, 3 scfm total gas is approximately 2.49 scfm (149.2 scfh) methane. This compressor emission rate, which was used for all industry segments, was converted to an annual mass emission rate by applying segment-specific pressurized factors, then converted to a mass basis.
      The estimated percent reduction in methane emissions that would be achievable from reducing 149.2 scfh methane/cylinder to 11.5 scfh methane/cylinder (average emissions from a newly installed rod packing/cylinder) is 92 percent. We applied this percent reduction in methane emissions and estimated reciprocating compressor methane and VOC emission reductions that would be achieved from repairing/replacing rod packing based on the annual flow rate monitoring option. The calculations assume that all cylinders are emitting at 3 scfm, and that the rod packings for all compressor cylinders are replaced. This represents the emission reductions expected for the year in which the rod packings are replaced. Emissions would be expected to increase (and emission reductions decrease) in subsequent years until the next time the annual measurements require that the rod packing be replaced.
      The capital and annual costs of replacing the rod packings are the same as presented above for the fixed interval rod packing replacement option. In addition, this option would include the costs associated with the annual flow measurements. The estimated costs of this monitoring are based on the costs for annual flow rate monitoring under GHGRP subpart W for similar flow rate annual measurement requirements ($597). The capital costs associated with replacing compressor rod packing would only occur in the year when packing is required to be replaced. The monitoring costs would be incurred every year.
	Additionally, the cost estimates assume that the packing of all compressor cylinders would need to be replaced (which is unlikely to be the case in many instances) and are therefore conservative estimates. Support information for the California rule cites data indicating that approximately 14 percent of compressors measurements indicated a leak rate of over 2 scfm per cylinder. Based on an average of 3.45 cylinders/compressor, California assumed that the packing for 2 cylinders/compressor would need to be replaced to come into compliance with the 2 scfm standard (57.9 percent). 
	Using the single pollutant approach, where all the costs are assigned to the reduction of one pollutant, the cost effectiveness of the annual monitoring option is approximately $230 per ton of methane reduced for gathering and boosting ($40 per ton if gas savings are considered), $110 per ton of methane reduced for the processing segment (net savings if gas savings are considered), $100 per ton of methane reduced for the transmission segment, and $110 per ton of methane reduced for the storage segment. Using the multipollutant approach, where half the cost of control is assigned to the methane reduction and half to the VOC reduction, the cost effectiveness of replacement of the reciprocating rod packing based on the annual monitoring approach is approximately $110 per ton of methane reduced for gathering and boosting ($20 per ton if gas savings are considered), $60 per ton of methane reduced for the processing segment (net savings if gas savings are considered), $50 per ton of methane reduced for the transmission segment, and $60 per ton of methane reduced for the storage segment.
	Using the single pollutant approach, where all the costs are assigned to the reduction of one pollutant, the VOC cost effectiveness of the annual monitoring option is approximately $810 per ton of VOC reduced for gathering and boosting ($160 per ton if gas savings are considered), $380 per ton of VOC reduced for the processing segment (net savings if gas savings are considered), $3,700 per ton of VOC reduced for the transmission segment, and $4,100 per ton of VOC reduced for the storage segment. Using the multipollutant approach, where half the cost of control is assigned to the methane reduction and half to the VOC reduction, the cost effectiveness of replacement of the reciprocating rod packing based on the annual monitoring approach is approximately $410 per ton of VOC reduced for gathering and boosting ($80 per ton if gas savings are considered), $190 per ton of VOC reduced for the processing segment net savings if gas savings are considered, $1,850 per ton of VOC reduced for the transmission segment, and $2,040 per ton of VOC reduced for the storage segment.
	We also assessed the incremental cost effectiveness of the annual monitoring option compared to the fixed 3-year/26,000 replacement schedule. Using the single pollutant approach, where all the costs are assigned to the reduction of one pollutant, the incremental cost effectiveness (without natural gas savings) from the fixed replacement option to the annual monitoring option for methane is approximately $130 per ton for gathering and boosting stations, $210 per ton for processing plants, $180 per ton for transmission stations, and $140 per ton for storage facilities. For VOC, the incremental cost effectiveness is approximately $480 per ton for gathering and boosting stations, $750 per ton for processing plants, $6,600 per ton for transmission stations, and $5,150 per ton for storage facilities. 
      The cost effectiveness of both options (fixed schedule and annual monitoring) are reasonable for methane and VOC using either the single pollutant or multipollutant approach. The incremental cost effectiveness in going from the fixed schedule option to the annual monitoring option is reasonable for all scenarios, with the exception of VOC for transmission stations. Therefore, based on the consideration of the costs in relation to the emission reductions, the EPA finds that the annual monitoring option is the most reasonable option. 
      Further, as discussed above, California requires reciprocating compressor annual rod packing flow rate monitoring and repair and or replacement of the packing where flow rate monitoring indicates a measurement that exceeds 2 scfm. This further supports the reasonableness of a monitoring program.
	Neither the fixed schedule rod packing replacement option nor the rod packing replacement based on annual monitoring option would result in secondary emissions impacts as both options would reduce the escape of natural gas from the piston rod. No wastes would be created (other than the worn packing that is being replaced) and no wastewater would be generated. An advantage related to the replacement of rod packing for reciprocating compressors based on annual rod packing monitoring is that it would only require replacement of the rod packing where monitoring of the rod packing indicates wear and increasing flow rate/emissions to unacceptable levels. This optimizes the output of capital expenditures to focus on emissions control where an increased emissions potential is identified. 
	In light of the above we determined that annual rod pack flow rate monitoring and replacement of the packing where flow rate monitoring indicates a measurement that exceeds 2 scfm represents BSER for NSPS OOOOb for this proposal for all segments including reciprocating compressors located at centralized productions facilities (with the exception of compressors at stand-alone well sites). As in the 2016 NSPS OOOOa, the EPA is proposing to allow the collection and routing of emissions to a process as an alternative standard because that option would achieve emission reductions equivalent to, or greater than, the proposed standard for NSPS OOOOb. 
	The affected facility based on EPA's review would continue to be each reciprocating compressor not located at a well site, or an adjacent well site and servicing more than one well site. As discussed above, the EPA is proposing a new definition for a "centralized production facility". The EPA is proposing to define centralized production facilities separately from well sites because the number and size of equipment, particularly reciprocating and centrifugal compressors, is larger than standalone well sites which would not be included in the proposed definition of "centralized production facilities". Thus, the EPA is proposing that reciprocating compressors located at centralized production facilities would be subject to the standards in the NSPS in OOOOb, but reciprocating compressors at well sites (standalone well sites) would not.
2. EG OOOOc
      The EPA evaluated BSER for the control of methane from existing reciprocating compressors (designated facilities) in all segments in the Crude Oil and Natural Gas source category covered by the proposed NSPS OOOOb and translated the degree of emission limitation achievable through application of the BSER into a proposed presumptive standard for these facilities that essentially mirrors the proposed NSPS OOOOb.
      First, based on the same criteria and reasoning as explained above, the EPA is proposing to define the designated facility in the context of existing reciprocating compressors as those that commenced construction on or before [INSERT DATE OF PUBLICATION OF PROPOSED RULE IN THE FEDERAL REGISTER]. Based on information available to the EPA, we did not identify any factors specific to existing sources that would indicate that the EPA should alter this definition as applied to existing sources. Next, the EPA finds that the control measures evaluated for new sources for NSPS OOOOb are appropriate for consideration for existing sources under the EG OOOOc. The EPA finds no reason to evaluate different, or additional, control measures in the context of existing sources because the EPA is unaware of any control measures, or systems of emission reduction, for reciprocating compressors that could be used for existing sources but not for new sources. Next, the methane emission reductions expected to be achieved via application of the control measures identified above to new sources are also expected to be achieved by application of the same control measures to existing sources. The EPA finds no reason to believe that these calculations would differ for existing sources as compared to new sources because the EPA believes that the baseline emissions of an uncontrolled source are the same, or very similar, and the efficiency of the control measures are the same, or very similar, compared to the analysis above. This is also true with respect to the costs, non-air environmental impacts, energy impacts, and technical limitations discussed above for the control options identified.
      The EPA has not identified any costs associated with applying these controls at existing sources, such as retrofit costs, that would apply any differently than, or in addition to, those costs assessed above regarding application of the identified controls to new sources. The cost effectiveness values for the proposed presumptive standard of replacement of the rod packing based on an annual monitoring threshold is approximately $230 per ton of methane reduced ($40 per ton if gas savings are considered) for the gathering and boosting segment (including reciprocating compressors located at centralized tank facilities), $110 per ton of methane reduced for the processing segment (net savings if gas savings are considered), $100 per ton of methane reduced for the transmission segment, and $110 per ton of methane reduced for the storage segment.
      In summary, the EPA did not identify any factors specific to existing sources, as opposed to new sources, that would alter the analysis above for the proposed NSPS OOOOb as applied to the designated pollutant (methane) and the designated facilities (reciprocating compressors). As a result, the proposed presumptive standard for existing reciprocating compressors is as follows.
      For reciprocating compressors in the gathering and boosting segment (including reciprocating compressors located at centralized tank facilities), processing, and transmission and storage segments, the presumptive standard is replacement of the rod packing based on an annual monitoring threshold. Specifically, the presumptive standard would require an owner or operator of a reciprocating compressor designated facility to monitor the rod packing flow rate annually. When the measured leak rate exceeds 2 scfm (in pressurized mode), the standard would require replacement of the rod packing. As an alternative, the presumptive standard would be routing rod packing emissions to a process via a closed vent system under negative pressure.
F. Proposed Standards for Centrifugal Compressors
1. NSPS OOOOb
a. Background
      The 2012 NSPS OOOO and the 2016 NSPS OOOOa applied to each wet seal compressor not located at a well site, or an adjacent well site and servicing more than one well site. The 2016 NSPS OOOOa required methane and VOC emissions be reduced from each centrifugal compressor wet seal fluid degassing system by 95.0 percent. Compliance with this requirement allowed routing of emission from the wet seal fluid degassing system to a control device or to a process. Dry seal compressors were not subject to requirements under the 2016 NSPS OOOOa. 
      In determining BSER for wet seal compressors in 2016, the EPA determined that the previous determination for NSPS OOOO conducted in 2011/2012 still represented BSER for the control of VOC in 2016. In addition, the EPA determined that analogous control of methane represented BSER. In the 2012 determinations, the EPA conducted analyses of the cost and emission reductions of (1) requiring the conversion of a wet seal system to a dry seal system, and (2) routing to a control device or process. The 2011 NSPS OOOO rule proposed an equipment standard that would have required the use of dry seals to limit the VOC emissions from new centrifugal compressors. At that time, the EPA solicited comments on the emission reduction potential, cost, and any technical limitations for the option of routing the gas back to a low-pressure fuel stream to be combusted as fuel gas. In addition, in 2011, the EPA solicited comments on whether there are situations or applications where a wet seal is the only option, because a dry seal system is infeasible or otherwise inappropriate. The EPA received information indicating that the integration of a centrifugal compressor into an operation may require a certain compressor size or design that is not available in a dry seal model, and in the case of capture of emissions with routing to a process, there may not be down-stream equipment capable of handling a low-pressure fuel source. In the final 2012 NSPS OOOO rule, the EPA made the determination that the replacement of wet seals with dry seals and routing to a process was not technically feasible or practical for some centrifugal compressors, and also that the costs per ton of emissions reduced were reasonable for routing emissions to a control device or process. No other more stringent control options were evaluated at that time. During the development of the 2016 NSPS OOOOa rule, the EPA reviewed available information on control options for wet seal compressors and did not identify any new information to indicate that this has changed.
      For this review, the EPA also focused on these control options. BSER was evaluated for wet-seal centrifugal compressors at gathering and boosting stations (considered to be representative of emissions from centrifugal compressors at centralized production facilities) in the production segment, at natural gas processing plants, and at sites in the transmission and storage segment. During the development of the 2012 NSPS OOOO and 2016 NSPS OOOOa rulemakings, our data indicated that there were no centrifugal compressors located at well sites. Since the 2012 NSPS OOOO and 2016 NSPS OOOOa rulemakings, we have not received information that would change our understanding that there are no centrifugal compressors in use at well sites. Information included in the GHGI for production segment compressors does not distinguish the type of compressor (e.g., reciprocating versus centrifugal). As a result, we have not evaluated well site centrifugal compressor regulatory options in our review.
	However, as discussed in section XI.K (Centralized Production Facilities) of this preamble, the EPA believes the definition of "well site" in NSPS OOOOa may cause confusion regarding whether centrifugal compressors located at centralized production facilities are also exempt from the standards. The EPA is proposing a new definition for a "centralized production facility". The EPA is proposing to define centralized production facilities separately from well sites because the number and size of equipment, particularly reciprocating and centrifugal compressors, is larger than standalone well sites which would not be included in the proposed definition of "centralized production facilities". This proposal is necessary in the context of centrifugal compressors to distinguish between these compressors at centralized production facilities where the EPA has determined that the standard should apply, and compressors at standalone well sites where the EPA has determined that the standard should not apply. In our current analysis, described below, we consider the centrifugal compressor gathering and boosting segment emission factor as being representative of centrifugal compressor emissions located at centralized production facilities. As such, the EPA is proposing that centrifugal compressors located at centralized production facilities would be subject to the standards in NSPS OOOOb and the EG in OOOOc, but centrifugal compressors at well sites (standalone well sites) would not.
      In addition to the requirement to reduce methane and VOC emissions from each centrifugal compressor wet seal fluid degassing system by 95.0 percent, the 2016 NSPS OOOOa requires compressor components to be monitored as fugitive emissions components and leaks found are to be repaired under the fugitive emissions monitoring requirements of 40 CFR 60.5397a. The monitoring frequency depends on source (i.e., well sites, compressor stations) and sector segment. These fugitive emissions components were not considered part of the centrifugal compressor affected facility. 
      Based on the EPA's review of NSPS OOOOa, we are proposing that BSER continues to be that methane and VOC emissions be reduced from each centrifugal compressor wet seal fluid degassing system by 95.0 percent. 
      Centrifugal compressors use a rotating disk or impeller to increase the velocity of the natural gas where it is directed to a divergent duct section that converts the velocity energy to pressure energy. These compressors are primarily used for continuous, stationary transport of natural gas in the processing and transmission systems. Some centrifugal compressors use wet (meaning oil) seals around the rotating shaft to prevent natural gas from escaping where the compressor shaft exits the compressor casing. The wet seals use oil which is circulated at high pressure to form a barrier against compressed natural gas leakage. The circulated oil entrains and adsorbs some compressed natural gas that may be released to the atmosphere during the seal oil recirculation process. Off gassing of entrained natural gas from wet seal centrifugal compressors is not suitable for sale and is either released to the atmosphere, flared, or routed back to a process.  
      Some centrifugal compressors utilize dry seal systems. Dry seal systems minimize leakage by using the opposing force created by hydrodynamic grooves and springs. The hydrodynamic grooves are etched into the surface of the rotating ring affixed to the compressor shaft. When the compressor is not rotating, the stationary ring in the seal housing is pressed against the rotating ring by springs. When the compressor shaft rotates at high speed, compressed natural gas has only one pathway to leak down the shaft, and that is between the rotating and stationary rings. This natural gas is pumped between the grooves in the rotating and stationary rings. The opposing force of high-pressure natural gas pumped between the rings and springs trying to push the rings together creates a very thin gap between the rings through which little natural gas can leak. While the compressor is operating, the rings are not in contact with each other and, therefore, do not wear or need lubrication. O-rings seal the stationary rings in the seal case. Historically, the EPA has considered dry seal centrifugal compressors to be inherently low-emitting and has never required control of emissions from dry seal compressors. The EPA has received feedback, however, that the EPA may have overestimated emissions from wet seal centrifugal compressors as compared to dry seal compressors and is soliciting comment on wet seal compressor and dry seal compressor emissions in this proposed action (discussed below). 
      The 2021 U.S. GHGI estimates over 540,000 metric tpy of methane emissions in 2019 from compressors from natural gas systems. The inventory does not include a breakdown of reciprocating compressor and centrifugal compressor types in the production segment and at gathering and boosting stations. For the natural gas processing and transmission segments, wet seal compressor methane emissions are estimated to be about 78,700 metric tons and dry seal compressor methane estimated emissions are estimated to be about 88,000 metric tons. The wet seal and dry seal compressor methane emission estimates reflect the increasing prevalence of the use of dry seals over wet seals and emissions control requirements that require the control of emissions from wet seal compressors. The methane emissions from compressors (both reciprocating and centrifugal compressors) represent 14 percent of the total methane emissions from natural gas systems in the Oil and Natural Gas Industry sector.
c. Affected Facility
      For purposes of the NSPS, the centrifugal compressor affected facility is a single centrifugal compressor using wet seals. A centrifugal compressor located at a well site, or an adjacent well site and servicing more than one well site, is not an affected facility under the proposed rule for NSPS OOOOb. As discussed above, the EPA is proposing that the affected facility includes centrifugal compressors located at centralized production facilities and the affected facility exception for "a well site, or an adjacent well site servicing more than one well site" applies to standalone well sites and not centralized production facilities. 
d. BSER Analysis
      The methodology we used for estimating emissions from compressors is consistent with the methodology developed for the 2012 NSPS OOOO BSER analysis, which was also used to support the 2016 NSPS OOOOa BSER. The wet-seal centrifugal compressor methane uncontrolled emission factors are based on the volumetric emission factors used for the GHGI, which were converted to a mass emission rate using a density of 41.63 pounds of methane per thousand cubic feet. The VOC emissions were calculated using the ratio of 0.278 pounds VOC per pound of methane for the production and processing segments, and 0.0277 pounds VOC per pound of methane for the transmission and storage segment. The resulting baseline uncontrolled emissions per centrifugal compressor are 157 tpy methane (43.5 tpy VOC) from wet-seal compressors at gathering and boosting sites, 211 tpy methane (58.7 tpy VOC) from wet-seal compressors at natural gas processing plants, 157 tpy methane (4.3 tpy VOC) from wet-seal compressors at transmission compressor stations, and 117 (3.24 tpy VOC) from wet-seal compressors at storage facilities. Since the emission factors for dry seal compressors are approximately 90 percent lower than wet seal compressors, the EPA considered requiring dry seals as a replacement to wet seals as a control option in 2011. The EPA proposed dry seals as a replacement to wet seals to control VOC emissions at that time. Based on comments received on the proposal that dry seal compressors were not feasible in all instances based on costs and technical reasons, the EPA did not finalize the proposal that dry seal compressors represented BSER. Instead, the EPA separately evaluated the control options for wet seal compressors (77 FR 49499-49500, 49523, August 16, 2012). In the 2015 NSPS OOOOa proposed rule, the EPA maintained that available information since the 2012 NSPS OOOO rule continued to show that dry seal compressors cannot be use in all circumstances. The EPA has not identified any new information since that time that indicates that dry seal compressors as a replacement for wet seal compressors is technically feasible in all circumstances. Thus, we did not evaluate the replacement of a wet seal system with a dry seal system as BSER for controlling emissions from wet seal systems for the NSPS OOOOb proposal.  
      In addition to soliciting comment and information on lower-emitting wet seal compressor designs (that emit less than dry seal compressors), the EPA is soliciting information on dry seal compressor emissions. Feedback received (noted above) on lower emitting wet seal compressor designs included concern that lower emitting wet seal systems were being replaced by higher emitting (but still low emitting) dry seal systems because they were not subject to the NSPS. Given that the trend has been that wet seal compressor systems are increasingly being replaced by dry seal compressor systems, the EPA solicits comments on dry seal compressor emissions and whether/and to what degree operational or malfunctioning conditions (e.g., low seal gas pressure, contamination of the seal gas, lack of supply of separation gas, mechanical failure) have the potential to impact methane and VOC emissions. The EPA also solicits comment on whether owners and operators implement standard operating procedures to identify and correct operational or malfunction conditions that have the potential to increase emissions from dry seal systems. Finally, the EPA solicits comments on whether we should consider evaluating BSER and developing NSPS standards for dry seal compressors.
      The control options to reduce emissions from centrifugal compressors evaluated include control techniques that reduce emissions from leaking of natural gas from wet seal compressors by capturing leaking gas and route it either to (1) a control device (combustion device), or (2) to the process. We evaluated the costs and impacts of both of these options.
      Combustion devices are commonly used in the Crude Oil and Natural Gas Industry to combust methane and VOC emission streams. Combustors are used to control VOC and methane emissions in many industrial settings, since the combustor can normally handle fluctuations in concentration, flow rate, heating value and inert species content. A combustion device generally achieves 95 percent reduction of methane and VOC when operated according to the manufacturer instructions. For this analysis, we assumed that the entrained natural gas from the seal oil that is removed in the degassing process would be directed to a combustion device that achieves a 95 percent reduction of methane and VOC emissions. This option was determined to be BSER under the 2011 NSPS OOOO and 2016 NSPS OOOOa rules. The combustion of the recovered gas creates secondary emissions of hydrocarbons (NOx, CO2, and CO emissions). Routing the captured gas from the centrifugal compressor wet seal degassing system to a combustion device has associated capital and operating costs.
      The capital and annual costs for the installation of a combustion device (an enclosed flare for the analysis) were calculated using the methodology in the EPA Control Cost Manual. The capital costs of a flare and the equipment (closed vent system) necessary to route emissions to the flare are based on costs from the 2011 NSPS OOOO TSD and 2016 NSPS OOOOa TSD. These costs were updated to 2019 dollars. The updated capital costs of $80,930 were annualized at 7 percent based on an equipment life of 10 years. The total annualized capital costs were estimated to be $11,520. The annual operating costs are also based on the 2011 NSPS OOOO TSD and 2016 NSPS OOOOa TSD. These costs were updated to 2019 dollars. The 2019 annual operating costs were estimated to be $117,160. The combined annualized capital and operating costs per compressor per year is an estimated $128,680. There is no cost savings estimated for this option because the recovered natural gas is combusted. The costs presented for gathering and boosting segment centrifugal compressors represent the estimated costs assumed for centrifugal compressors located at centralized production facilities.
      Using the single pollutant approach, where all the costs are assigned to the reduction of one pollutant, the cost effectiveness of routing emissions from a wet seal system to a new flare for methane emissions is $870 per ton of methane reduced for the transmission segment and gathering and boosting, $640 per ton of methane reduced for the processing segment, and $1,160 per ton of methane reduced for the storage segment. Using the multipollutant approach, where half the cost of control is assigned to the methane reduction and half to the VOC reduction, the cost effectiveness of routing emissions from a wet seal system to a new flare for methane emissions is $430 per ton of methane reduced for the transmission segment and gathering and boosting, $320 per ton of methane reduced for the processing segment, and $580 per ton of methane reduced for the storage segment.
      Using the single-pollutant approach, where all the costs are assigned to the reduction of one pollutant, the cost effectiveness of routing emissions from a wet seal system to a new flare for VOC emissions is $3,100 per ton of VOC reduced for gathering and boosting, $2,300 per ton of VOC reduced for the processing segment, $31,200 per ton of VOC reduced for the transmission segment, and $41,800 per ton of VOC reduced for the storage segment. Using the multipollutant approach, where half the cost of control is assigned to the methane reduction and half to the VOC reduction, the cost effectiveness of routing emissions from a wet seal system to a new flare for VOC emissions is $1,600 per ton of VOC reduced for gathering and boosting, $1,200 per ton of VOC reduced for the processing segment, $15,600 per ton of VOC reduced for the transmission segment, and $20,900 per ton of VOC reduced for the storage segment. 
      In addition to an owner or operator having the option to capture emissions and routing to a new combustion control device, a less costly option that may be available could be for owners and operators to capture and route emissions to a combustion control device installed for another source (e.g., a control device that is already on site to control emissions from another emissions source). The costs, which are provided in the Technical Support Document for this rulemaking, would be for the ductwork to capture the emissions and route them to the control device. The analysis assumes that the combustion control device on site achieves a 95 percent reduction in emissions of methane and VOC.
      Another option for reducing methane and VOC emissions from the compressor wet seal fluid degassing system is to route the captured emissions back to the compressor suction or fuel system, or other beneficial use (referred to collectively as routing to a process). Routing to a process would entail routing emissions via a closed vent system to any enclosed portion of a process unit (e.g., compressor or fuel gas system) where the emissions are predominantly recycled, consumed in the same manner as a material that fulfills the same function in the process, transformed by chemical reaction into materials that are not regulated materials, incorporated into a product, or recovered. Emissions that are routed to a process are assumed to result in the same or greater emission reductions as would have been achieved had the emissions been routed through a closed vent system to a combustion device. For purposes of this analysis, we assumed that routing methane and VOC emissions from a wet seal fluid degassing system to a process reduces VOC emissions greater than or equal to a combustion device (i.e., greater than or equal to 95 percent). There are no secondary impacts with the option to control emissions from centrifugal wet seals by capturing gas and routing to the process. 
      The capital cost of a system to route the seal oil degassing system to a process is estimated to be $26,210 ($2,019), The estimated costs include an intermediate pressure degassing drum, new piping, gas demister/filter, and a pressure regulator for the fuel line. The annual costs were estimated to be $2,880 (without savings) assuming a 15-year equipment life at 7 percent interest. Because the natural gas is not lost or combusted, the value of the natural gas represents a savings to owners and operators in the production (gathering and boosting) and processing segments. Savings were estimated using a natural gas price of $3.13 per Mcf, which resulted in annual savings of $27,000 per year at gathering and boosting stations and $36,400 per year at processing plants. The annual cost savings are much greater than the annual costs, which results in an overall savings when they are considered.
      Using the single pollutant approach, where all the costs are assigned to the reduction of one pollutant, the cost effectiveness (without natural gas savings) of routing emissions from a wet seal system to a process for methane emissions is approximately $19 per ton of methane reduced for the transmission segment and gathering and boosting, $14 per ton of methane reduced for the processing segment, and $26 per ton of methane reduced for the storage segment. Using the multipollutant approach, where half the cost of control is assigned to the methane reduction and half to the VOC reduction, the cost effectiveness (without natural gas savings) of routing emissions from a wet seal system to a process for methane emissions is approximately $10 per ton of methane reduced for the transmission segment and gathering and boosting, $7 per ton of methane reduced for the processing segment, and $13 per ton of methane reduced for the storage segment. As noted above, there is an overall net savings if the value of the natural gas recovered is considered.
      Using the single pollutant approach, where all the costs are assigned to the reduction of one pollutant, the cost effectiveness (without natural gas savings) of routing emissions from a wet seal system to a process for VOC emissions is approximately $70 per ton of VOC reduced for gathering and boosting, $50 per ton of VOC reduced for the processing segment, $700 per ton of VOC reduced for the transmission segment, and $940 per ton of VOC reduced for the storage segment. Using the multipollutant approach, where half the cost of control is assigned to the methane reduction and half to the VOC reduction, the cost effectiveness (without natural gas savings) of routing emissions from a wet seal system to a process for VOC emissions is approximately $35 per ton of VOC reduced for gathering and boosting, $26 per ton of VOC reduced for the processing segment, $350 per ton of VOC reduced for the transmission segment, and $470 per ton of VOC reduced for the storage segment. As noted above, there is an overall net savings if the valued of the natural gas recovered is considered.
      The cost effectiveness of both options (routing emissions to a combustion device or to a process) are reasonable for methane for all of the evaluated segments, using both the single pollutant and multipollutant approaches. The cost effectiveness of routing emissions to a process are also reasonable for VOC for all of the evaluated segments, using both the single pollutant and multipollutant approaches. For routing emissions to a combustion device, the cost effectiveness is reasonable for the gathering and boosting and processing segments using the single pollutant and multipollutant approaches. Based on the consideration of the costs in relation to the emission reductions of both methane and VOC, the EPA finds that requiring emissions to be reduced from each centrifugal compressor using a wet seal by at least 95 percent (which can be achieved by either option) continues to be reasonable in the gathering and boosting (considered to be representative of emissions/costs from centrifugal compressors at centralized production facilities). processing, transmission and storage segments.
      The 2012 NSPS OOOO and the 2016 NSPS OOOOa require emissions be reduced from each centrifugal compressor wet seal fluid degassing system by at least 95.0 percent by routing emissions to a control device or to a process. States have generally adopted/incorporated this NSPS level of control (or a level of control that is substantially similar) in their state regulations for the control of emissions from centrifugal compressor sources using wet seals Owners and operators have successfully met this standard for almost a decade. These facts further demonstrate the reasonableness of this level of control. In the discussion above, we reviewed two options to reduce emissions from wet seal compressors that are both current regulatory options under the 2016 NSPS OOOOa: (1) capturing leaking gas and route to a combustion device (flare), or (2) capturing leaking gas and route to the process. Under the 2016 NSPS OOOOa, the level of control determined based on BSER was that methane and VOC emissions be reduced from each centrifugal compressor wet seal fluid degassing system by 95 percent or greater. The EPA has not identified any other control options or any other federal, state, or local requirements that would achieve a greater reduction in methane and VOC emissions from centrifugal compressor wet seal systems. Although capturing leaking gas and routing to the process has the advantage of both reducing emissions by at least 95 percent or greater and capturing the natural gas (resulting in a natural gas savings), the EPA has received feedback in the development of the 2012 NSPS OOOO rule that this option may not be a viable option in situations where there may not be down-stream equipment capable of handling a low-pressure fuel source. During the development of the 2016 NSPS OOOOa rule, the EPA reaffirmed that information since the development of the 2012 NSPS OOOO rule continues to show that capturing leaking gas and routing to the process cannot be used in all circumstances. No new information has been identified since the development of the 2016 NSPS OOOOa rule to indicate that capturing leaking gas and routing to the process can be achieved in all circumstances (80 FR 56619, September 18, 2015). Thus, by establishing a 95 percent methane and VOC emissions control level as BSER, an owner or operator has the option of routing emissions to a process where it is a viable option, or to a combustion device where routing to a process is not a viable option. If an owner or operator chooses to route to a process to meet the 95 percent level of control, there are no secondary impacts. If an owner or operator chooses to route to a combustion device to meet the 95 percent level of control, the combustion of the recovered gas creates secondary emissions of hydrocarbons (NOx, CO2, and CO emissions).
      The costs, emission reductions, and cost effectiveness values were presented above for collecting the wet seal compressor emissions and routing them to both a combustion device and to a process to achieve at least a 95 percent control. The EPA considers the cost effectiveness of both of these control options reasonable across all segments evaluated (i.e., the gathering and boosting portion of production, processing, transmission, storage) for the reduction of methane emissions under the single pollutant approach and multipollutant approach. As discussed above, in our current analysis, we consider the centrifugal compressor gathering and boosting segment emission factor as being representative of centrifugal compressor emissions located at centralized production facilities. Thus, the cost analysis performed for the gathering and boosting segment represents the estimated costs of evaluated options for centrifugal compressors with wet seals located at centralized storage facilities.
      In light of the above, we determined that reducing methane and VOC emissions from each centrifugal compressor wet seal fluid degassing system by 95 percent or greater continues to represent BSER for NSPS OOOOb for this proposal. The affected facility based on EPA's review would continue be each wet seal compressor not located at a well site, or an adjacent well site and servicing more than one well site. As discussed above, the EPA is proposing a new definition for a "centralized production facility". The EPA is proposing to define centralized production facilities separately from well sites because the number and size of equipment, particularly reciprocating and centrifugal compressors, is larger than standalone well sites which would not be included in the proposed definition of "centralized production facilities". Thus, the EPA is proposing that centrifugal compressors located at centralized production facilities would be subject to the standards in the NSPS in OOOOb, but centrifugal compressors at well sites (standalone well sites) would not.
2. EG OOOOc
      The EPA evaluated BSER for the control of methane from existing centrifugal compressors using wet seals (not located at a well site, or an adjacent well site and servicing more than one well site) (designated facilities) in all segments in the Crude Oil and Natural Gas source category covered by the proposed NSPS OOOOb and translated the degree of emission limitation achievable through application of the BSER into a proposed presumptive standard for these facilities that essentially mirrors the proposed NSPS OOOOb.
      First, based on the same criteria and reasoning as explained above, the EPA is proposing to define the designated facility in the context of existing centrifugal compressors using wet seals (not located at a well site, or an adjacent well site and servicing more than one well site) as those that commenced construction on or before [INSERT DATE OF PUBLICATION OF PROPOSED RULE IN THE FEDERAL REGISTER]. Based on information available to the EPA, we did not identify any factors specific to existing sources that would indicate that the EPA should alter this definition as applied to existing sources. Next, the EPA finds that the control measures evaluated for new sources for NSPS OOOOb are appropriate for consideration for existing sources under the EG OOOOc. The EPA finds no reason to evaluate different, or additional, control measures in the context of existing sources because the EPA is unaware of any control measures, or systems of emission reduction, for centrifugal compressors that could be used for existing sources but not for new sources. Next, the methane emission reductions expected to be achieved via application of the control measures identified above to new sources are also expected to be achieved by application of the same control measures to existing sources. The EPA finds no reason to believe that these calculations would differ for existing sources as compared to new sources because the EPA believes that the baseline emissions of an uncontrolled source are the same, or very similar, and the efficiency of the control measures are the same, or very similar, compared to the analysis above. This is also true with respect to the costs, non-air environmental impacts, energy impacts, and technical limitations discussed above for the control options identified.
      The EPA has not identified any costs associated with applying these controls at existing sources, such as retrofit costs, that would apply any differently than, or in addition to, those costs assessed above regarding application of the identified controls to new sources. The cost effectiveness values for the proposed presumptive standard of reducing methane emissions from each centrifugal compressor wet seal fluid degassing system by 95 percent or greater are based on the cost effectiveness of routing emissions from a wet seal system to a flare or to a process. The cost effectiveness of routing emissions from a wet seal system to a new flare for methane emissions is $870 per ton of methane reduced for the transmission segment and gathering and boosting, $640 per ton of methane reduced for the processing segment, and $1,160 per ton of methane reduced for the storage segment. The cost effectiveness (without natural gas savings) of routing emissions from a wet seal system to a process for methane emissions is approximately $19 per ton of methane reduced for the transmission segment and gathering and boosting, $14 per ton of methane reduced for the processing segment, and $26 per ton of methane reduced for the storage segment.
      In summary, the EPA did not identify any factors specific to existing sources, as opposed to new sources, that would alter the analysis above for the proposed NSPS OOOOb as applied to the designated pollutant (methane) and the designated facilities (centrifugal compressors using wet seals). As a result, the proposed presumptive standard for existing centrifugal compressors using wet seals is as follows.
      For centrifugal compressors using wet seals in the gathering and boosting segment (including centrifugal compressors using wet seals located at centralized tank facilities), processing, and transmission and storage segments, the presumptive standard is to reduce methane emissions by at least 95 percent. An owner or operator can meet this presumptive standard by routing methane emissions to a control device or process that reduces emissions by at least 95 percent. As discussed previously, the EPA is proposing a new definition for a "centralized production facility". The EPA is proposing to define centralized production facilities separately from well sites because the number and size of equipment, particularly reciprocating and centrifugal compressors, is larger than standalone well sites which would not be included in the proposed definition of "centralized production facilities". Thus, the EPA is proposing that centrifugal compressors located at centralized production facilities would be subject to the standards in the EG in OOOOc, but centrifugal compressors at well sites (standalone well sites) would not.
G. Proposed Standards for Pneumatic Pumps
1. NSPS OOOOb
a. Background
      In the 2016 NSPS OOOOa, the EPA established GHG (in the form of limitations on methane emissions) and VOC standards for natural gas-driven diaphragm pneumatic pumps located at well sites. This standard required that natural gas emissions be reduced by 95.0 percent by routing to an existing control device if (1) a control device was onsite, (2) the control device could achieve a 95.0 percent reduction, and (3) it was technically feasible to route the emissions to the control devise. The standard did not require the installation of a control device solely for the purpose of complying with the 95.0 percent reduction for the emissions from pneumatic pumps. It also allowed the option of routing emissions to a process. At natural gas processing plants, the EPA established a standard that required a natural gas emission rate of zero (i.e., that prohibited methane and VOC emissions from pneumatic pumps). 
      As a result of the review of these requirements and the previous BSER determination, the EPA is proposing methane and VOC standards in NSPS OOOOb for natural gas driven diaphragm pneumatic pumps located at well sites and all other sites in the production segment, natural gas transmission compressor stations, and natural gas storage facilities. Specifically, each natural gas driven pneumatic pump is an affected facility. The EPA is proposing that methane and VOC emissions from natural gas driven diaphragm pumps in these segments be reduced by 95.0 percent or routed to a process, provided that there is an existing control device onsite or it is technically feasible to route the emissions to a process. The EPA is proposing to retain the technical infeasibility provisions of NSPS OOOOa for purposes of NSPS OOOOb. If there is a control device onsite, the owner or operator is not required to route emissions to that control device if it is not technically feasible to do so, even for new construction sites which the EPA had previously referred to as "greenfield" sites. The EPA is also proposing to retain in NSPS OOOOb the exception to the 95.0 percent reduction requirement if there is a control device onsite that it is technically feasible to route to that cannot achieve that level of reduction but can achieve a lower level of reductions. In those situations, the emissions from the pump are still to be routed to the control device and controlled at the level that the device can achieve. The EPA is also proposing a prohibition on methane and VOC emissions from pneumatic pumps at natural gas processing plants. The proposed pneumatic pump affected facility is each natural gas driven pneumatic pump. While zero emissions pneumatic pumps would not technically be affected facilities, the EPA would encourage owners and operators to maintain documentation to be able to demonstrate that there are no methane or VOC emissions from the pumps.
      This BSER for reducing methane and VOC from pneumatic pumps are the same as those for the 2016 NSPS OOOOa, except that the EPA determined that the NSPS OOOOa levels of control also represent BSER for all sites in the production segment (including gathering and boosting stations), and for all transmission and storage sites.
      As discussed below, a primary reason that the EPA is unable to conclude that requiring a natural gas emission rate of zero for production and transmission and storage facilities is BSER at this time is because proven technologies that eliminate natural gas emissions rely on electricity to function. This is analogous to the situation for pneumatic controllers. As discussed in section XII.C, for pneumatic controllers the EPA is proposing to subcategorize production and natural gas transmission and storage sites into those sites that have access to onsite power and those that do not. The EPA determined BSER separately for each subcategory and is proposing separate standards. We are soliciting comment on whether the EPA should utilize this same subcategorization approach, or a similar approach, for pneumatic pumps.
b. Description
      A pneumatic pump is a positive displacement reciprocating unit generally used by the Oil and Natural Gas Industry for one of four purposes: (1) hot oil circulation for heat tracing/freeze protection, (2) chemical injection, (3) moving bulk liquids, and (4) glycol circulation in dehydrators. There are two basic types of pneumatic pumps used in the Oil and Natural Gas Industry, diaphragm pumps and piston pumps. Pumps used for heat tracing/freeze protection circulate hot glycol or other heat-transfer fluids in tubing covered with insulation to prevent freezing in pipelines, vessels and tanks. These heat tracing/freeze protection pumps are usually diaphragm pumps. Chemical injection pumps are designed to inject precise amounts of chemical into a process stream to regulate operations of a plant and protect the equipment. Typical chemicals injected in an oil or gas field are biocides, demulsifiers, clarifiers, corrosion inhibitors, scale inhibitors, hydrate inhibitors, paraffin dewaxers, surfactants, oxygen scavengers, and H2S scavengers. These chemicals are normally injected at the wellhead and into gathering lines or at production separation facilities. Since the injection rates are typically small, the pumps are also small. They are often attached to barrels containing the chemical being injected. These chemical injection pumps are primarily piston pumps, although they can be small diaphragm pumps. Examples of the use of pneumatic pumps to transfer bulk liquids at oil and natural gas production sites include pumping motor oil or pumping out sumps. Pumps used for these purposes ae typically diaphragm pumps.
      Glycol dehydrator pumps recover energy from the high-pressure rich glycol/gas mixture leaving the absorber and use that energy to pump the low-pressure lean glycol back into the absorber. Glycol dehydrator pumps are controlled under the oil and gas NESHAPs (40 CFR 63, subparts HH and HHH), are not included as affected facilities for the 2016 NSPS OOOOa and were not included in the review for proposed NSPS OOOOb.
      Both diaphragm and piston pumps are positive displacement reciprocating pumps, meaning they use contracting and expanding cavities to move fluids. These pumps work by allowing a fluid (e.g., the heat transfer fluid, demulsifier, corrosion inhibitor, etc) to flow into an enclosed cavity from a low-pressure source, trapping the fluid, and then forcing it out into a high-pressure receiver by decreasing the volume of the cavity. The piston and diaphragm pumps have two major components, a driver side and a motive side, which operate in the same manner but with different reciprocating mechanisms. Pressurized gas provides energy to the driver side of the pump, which operates a piston or flexible diaphragm to draw fluid into the pump. The motive side of the pump delivers the energy to the fluid being moved in order to discharge the fluid from the pump. The natural gas leaving the exhaust port of the pump is either directly discharged into the atmosphere or is recovered and used as a fuel gas or stripping gas.  
      Diaphragm pumps work by flexing the diaphragm out of the displacement chamber, and piston pumps typically include plunger pumps with a large piston on the gas end and a smaller piston on the liquid end to enable a high discharge pressure with a varied but much lower pneumatic supply gas pressure.
      As noted above, energy is supplied to the driver side of the pump to operate the piston or diaphragm. Commonly, this energy is provided by pressurized gas. This gas can be compressed air, or "instrument air," provided by an electrically powered air compressor. In many situations across all segments of this industry, electricity is not available, and this energy is provided by pressurized natural gas (i.e., "natural gas-driven pneumatic pumps"). This energy can also be directly provided by electricity.
      Natural gas-driven pneumatic pumps emit methane and VOC as part of their normal operation. These emissions occur when the gas used in the pump stroke is exhausted to enable liquid filling of the liquid cavity of the pump. Emissions are a function of the amount of fluid pumped, the pressure of the pneumatic supply gas, the number of pressure ratios between the pneumatic supply gas pressure and the fluid discharge pressure, and the mechanical inefficiency of the pump. 
      The 2021 U.S. GHGI estimates almost 215,000 metric tpy of methane emissions from pneumatic pumps in the oil and natural gas production segment in 2019. Specifically, this includes almost 113,000 metric tpy from natural gas production, 75,000 from petroleum production, and 26,000 from gathering and boosting compressor stations. These emissions make up 5 percent of all methane emissions in the GHGI for the combined gas and oil production segment, and 2 percent of all methane emissions for gathering and boosting. The overall total, which represents 3 percent of the total methane emissions from this industry, does not include emissions from the processing, transmission, and storage segments which the EPA is now proposing to regulate under NSPS OOOOb. 
c. BSER Analysis
      Due to the differences in emissions, we conducted the BSER analysis separately for natural gas-driven diaphragm pneumatic pumps and natural gas-driven piston pneumatic pumps. The emission factor for diaphragm pneumatic pumps is 3.46 tpy of methane, while it is only 0.38 tpy of methane for piston pumps. The corresponding VOC emission factors are 0.96 tpy for the production segment and 0.096 tpy for the transmission and storage segments for diaphragm pumps, and 0.11 and 0.01 tpy for piston pumps, for production and transmission and storage segments, respectively.
      With the exception of the evaluation of instrument air systems, the BSER analysis for pneumatic pumps was conducted on an individual pump basis. This represents how an affected facility under the NSPS would be defined and also how a designated facility under the EG would be defined. 
      BSER was evaluated for all segments of the industry. The 2015 NSPS OOOOa proposal included methane and VOC standards for pneumatic pumps in the production and transmission and storage segment. However, the EPA did not finalize regulations for pneumatic pumps at gathering and boosting stations in the final 2016 NSPS OOOOa due to lack of data on the prevalence of the use of pneumatic pumps at gathering and boosting stations. Since that time, GHGRP subpart W has required that emissions from natural gas-driven pneumatic pumps be reported. As reported above, the 2021 GHGI estimates over 26,000 metric tpy of methane emissions from these pumps in the gathering and boosting segment in 2019. Similarly, the EPA did not include pneumatic pumps in the transmission and storage segments in the final 2016 NSPS OOOOa because we did not have a reliable source of information indicating the prevalence of pneumatic pumps or their emission rates in the transmission and storage segments. While the GHGI does not include emissions from pneumatic pumps in the transmission and storage segments, and the GHGRP does not require the reporting of emissions from these pumps in this segment, state rules (notably the California rule and the proposed New Mexico rule) do include requirements for natural gas driven pneumatic pumps at transmission and storage facilities. The EPA is soliciting comment on whether natural gas driven pneumatic pumps are used in the natural gas transmission and storage segment and to what extent.
      In 2015, the EPA identified several options for reducing methane and VOC emissions from natural gas-driven pumps: replace natural gas-driven pumps with instrument air pumps, replace natural gas-driven pumps with solar-powered direct current pumps (solar pumps), replace natural gas-driven pumps with electric pumps, route natural gas-driven pump emissions to a control device, and route natural gas-driven pump emissions to a process. The EPA re-evaluated that information as well as new information including updated GHGI and GHGRP information, as well as information from more recent state regulations. No additional options were identified at this time. Therefore, for this analysis for both the NSPS and the EG, the EPA re-evaluated these options as BSER. In the discussion below, the options to require technology that would eliminate methane and VOC emissions by requiring the use of a non-natural gas driven pumps are discussed, followed by a discussion of routing natural gas driven pumps to a control device.
      For this analysis, we first evaluated the options that would eliminate methane and VOC emissions from pneumatic pumps, specifically instrument/compressed air systems, electric pumps, and solar-powered pumps.
      Instrument air systems require a compressor, power source, dehydrator, and volume tank. No alterations are needed to the pump itself to convert from using natural gas to instrument air. However, they can only be utilized in locations with sufficient electrical power. Instrument air systems are more economical and, therefore, more common at facilities with a high concentration of pneumatic devices and where an operator can ensure the system is properly functioning. Electric pumps provide the same functionality as gas-driven pumps and are only restricted by the availability of a source of electricity. 
      Solar-powered pumps are a type of electric pump, except that the power is provided by solar-charged direct current (DC). Solar-powered pumps can be used at remote sites where a source of electricity is not available, and they have been shown to be able to handle a range of throughputs up to 100 gallons per day with maximum injection pressure around 3,000 pounds per square inch gauge (psig).
Zero Emissions Options
      Production and Transmission and Storage Segments. For the production and transmission and storage segments, we evaluated the costs and impacts of these "zero-emissions" options (See Chapter 9 of the Technical Support Document for this Rulemaking). We found that the cost-effectiveness of these options, for both diaphragm and piston pumps, were generally within the ranges that the EPA considers reasonable. However, for instrument air systems and electric pumps, our analysis assumes that electricity is available onsite. As noted above, in 2015, the EPA determined that a zero-emission standard for pumps in the production and transmission and storage segments was infeasible because (1) electricity is not available at all sites and (2) solar pumps are not technically feasible in all situations for which piston pumps and diaphragm pumps are needed. 80 FR 56625-56626. While we specifically requested comment on this determination, nothing was submitted that caused a reversal in this decision. At this time, we still do not have information that provides confidence that these limitations have been overcome and that zero-emission pneumatic pumps are technically feasible for all pneumatic pumps throughout the production and transmission and storage segments. Therefore, we are unable to conclude that this zero-emission option represents BSER in this proposal.
      However, a few states do prohibit emissions from pneumatic pumps throughout the Crude Oil and Natural Gas Industry. California prohibits the venting of natural gas to the atmosphere from pneumatic pumps through the use of compressed air or electricity, or by collecting all potentially vented natural gas with the use of a vapor collection system that undergoes periodic leak detection and repair. New Mexico has proposed a regulation that requires zero-emitting pumps at all production and transmission and storage sites that have access to electricity. 
      The EPA is soliciting comment on the basis for our proposed determination: that because electricity is not available at all sites and that there are applications at these sites where solar-powered pumps are not feasible the Agency is unable to conclude that the zero-emission options represent BSER. Also, as noted above, we are soliciting comment on an approach where the EPA would propose to subcategorize pneumatic pumps located in the production and transmission and storage sites based on availability of electricity and develop separate standards for each subcategory (similar to what the EPA is proposing for pneumatic controllers in section XII.C). Where air compressors have been installed to achieve non-emitting pneumatic controllers, pneumatic pumps could also be powered with air rather than natural gas.
      Natural gas processing plants. Natural gas processing plants are known to have a source of electrical power. Therefore, instrument air and electric pumps are technically feasible options at these facilities. 
      As the next step in the BSER determination, we evaluated capital and annual costs of compressed air systems for the natural gas processing plants. While electric pumps are an option at natural gas processing plants, we assumed that natural gas processing plants will elect to always use instrument air and an impacts analysis for electric pumps was not conducted. 
      The capital costs for an instrument air system were estimated to range from $4,500 to $39,500. The annual costs include the capital recovery cost (calculated at a 7 percent interest rate for 10 years), labor costs for operations and maintenance, and electricity costs. These are estimated to range from $11,300 to $81,350. Because gas emissions are avoided as compared to the use of natural gas-driven pumps, the use of an instrument air system will have natural gas savings realized from the gas not released. The EPA estimates that each diaphragm pump replaced will save 201 Mcf per year of natural gas from being emitted and each piston pump will save of 22 Mcf per year in the processing segment. The estimated value of the natural gas saved, based on $3.13 per Mcf, would range from $1,400 to $35,000 per year per plant. The annual costs, including these savings, ranges from $9,900 to $46,500. More information on this cost analysis is available in the Technical Support Document for this proposal.
      The resulting cost effectiveness, under the single pollutant approach where all the costs are assigned to the reduction of one pollutant, for the application of instrument air to achieve a 100 percent emission reduction at natural gas processing plants ranges from $420 to $1,470 per ton of methane eliminated. For VOC, these cost effectiveness values ranged from $1,520 to $5,290 per ton of VOC eliminated. Considering savings, these cost effectiveness values range from $240 to $1,300 per ton of methane eliminated and $870 to $4,600 per ton of VOC eliminated. Under the multipollutant approach where half the cost of control is assigned to the methane reduction and half to the VOC reduction, the cost effectiveness ranges from $210 to $730 per ton of methane eliminated and $760 to $2,640 per ton of VOC eliminated. Considering savings, the cost effectiveness values range from $120 to $650 per ton of methane eliminated and from $440 to $2,320 per ton of VOC eliminated. These values are well within the range of what the EPA considers to be reasonable for methane and VOC using both the single pollutant and multipollutant approaches.
      The 2016 NSPS OOOOa requires a natural gas emission rate of zero for pneumatic pumps at natural gas processing plants. Natural gas processing plants have successfully met this standard. Further, as discussed above several state agencies have rules that include this zero-emission requirement. This is a demonstration of the reasonableness of a natural gas emission rate of zero for pneumatic pumps at natural gas processing plants. 
      Based on the cost analysis summarized above, we find that the cost effectiveness for achieving a zero natural gas emission rate by installing compressed air systems at natural gas processing plants is reasonable for both methane and VOC under the single pollutant approach, as well as under the multipollutant approach. 
      Secondary impacts from the use of instrument air systems are indirect, variable, and dependent on the electrical supply used to power the compressor. These impacts are expected to be minimal, and no other secondary impacts are expected.
      In light of the above, we find that the BSER for reducing methane and VOC emissions from natural gas-driven piston and diaphragm pumps at gas processing plants is a natural gas emission rate of zero. This option results in a 100 percent reduction of emissions for both methane and VOC. Therefore, for NSPS OOOOb, we are proposing to require a natural gas emission rate of zero for all pneumatic pumps at natural gas processing plants.
Routing to a Control Device or VRU Options
      Above we stated our determination that the EPA is unable to conclude that this zero-emission option represents BSER in this proposal for pumps in the production and transmission and storage segments. Therefore, we evaluated the use of control devices to reduce methane and VOC emissions. This BSER analysis was conducted on an individual pump basis and diaphragm and piston pumps were evaluated separately.
      Combustors (e.g., enclosed combustion devices, thermal oxidizers and flares that use a high-temperature oxidation process) can be used to control emissions from natural gas-driven pumps. Combustors are used to control VOCs in many industrial settings, since the combustor can normally handle fluctuations in concentration, flow rate, heating value, and inert species content. The types of combustors installed in the Crude Oil and Natural Gas Industry can achieve at least a 95 percent control efficiency on a continuous basis. It is noted that combustion devices can be designed to meet 98 percent control efficiencies, and can control, on average, emissions by 98 percent or more in practice when properly operated. However, combustion devices that are designed to meet a 98 percent control efficiency may not continuously meet this efficiency in practice in the oil and gas industry due to factors such as variability of field conditions. 
      A related option for controlling emissions from pneumatic pumps is to route vapors from the pump to a process, such as back to the inlet line of a separator, to a sales gas line, or to some other line carrying hydrocarbon fluids for beneficial use, such as use as a fuel. Where a compressor is used to boost the recovered vapors into the line, this is often referred to as a vapor recovery unit (VRU). Use of a vapor recovery technology has the potential to reduce the VOC and methane emissions from natural gas-driven pneumatic pumps by 100 percent if all vapor is recovered. However, the effectiveness of the gas capture system and downtime for maintenance would reduce capture efficiency and therefore, we estimate that routing emissions from a natural gas-driven pump to a VRU and to a process can reduce the gas emitted by approximately 95 percent, while at the same time, capturing the gas for beneficial use.
      Based on a 95 percent reduction, the reduction in emissions in the production segment would be 3.29 tpy of methane and 0.91 tpy of VOC per diaphragm pump, and 0.36 tpy methane and 0.10 tpy VOC per piston pump. In the transmission and storage segment, the reduction in emissions would be be 3.29 tpy of methane and 0.09 tpy of VOC per diaphragm pump, and 0.36 tpy of methane and 0.01 ton per year of VOC per piston pump.
      Installation of a new combustion device or VRU. Costs for the installation of a new combustion device and a new VRU were evaluated. Installing a new combustion device has associated capital costs and operating costs. Based on the analysis conducted for the 2012 NSPS for a combustion device to control emissions from storage vessels, the capital cost for installing a new combustion device was $32,300 in 2008 dollars. We updated this to $38,500 to reflect 2019 dollars. Based on the life expectancy for a combustion device at 10 years, we estimate the annualized capital cost of installing a new combustion device to be $5,500 in 2019 dollars, using a 7 percent discount rate. The 2016 NSPS OOOOa TSD indicates the annual operating costs associated with a new combustion device were $17,000 in 2012 dollars, which we updated to $19,100 in 2019 dollars. Therefore, the total annual costs for a new combustion device are $24,600. Because the gas captured is combusted there are no gas savings associated with the use of a combustion device.
      Installing a new VRU would also have both capital costs and maintenance costs. We based the costs of a VRU on the analysis conducted for the 2012 NSPS for control of emissions from storage vessels, which is representative of the costs that would be incurred for a VRU used to reduce emissions from natural gas-driven pneumatic pumps. The capital cost and installation costs for a new VRU are estimated to be $116,900 (in 2019 dollars) and the annual operation and maintenance costs estimated to be $11,200 (in 2019 dollars). The total annualized cost of a new VRU is estimated to be $27,800, including the operation and maintenance cost and the annualized capital costs based on a 7 percent discount rate and 10-year equipment life. 
      Because there is potential for beneficial use of gas recovered through the VRU, the savings that would be realized for 95 percent of the gas that would have emitted and lost were estimated. The gas saved would equate to 191 Mcf per year from a diaphragm pump and 21 Mcf per year from a piston pump. This results in estimated annual savings of $600 per diaphragm pump and $65 per piston pump in the production segment. The resulting annual costs, considering these savings, are $27,200 per diaphragm pump and $27,700 per piston pump in the production segment. Transmission and storage facilities do not own the natural gas; therefore, savings from reducing the amount of natural gas emitted/lost was not applied for this segment.  More information on these cost analyses is available in the Technical Support Document for this proposal.
      The resulting cost effectiveness estimates for application of a new control device to reduce emissions from natural gas-driven pumps in the production segment by 95 percent, or the use of a VRU to route emissions back to a process, are discussed below under both the single pollutant approach, where all the costs are assigned to the reduction of one pollutant, and the multipollutant approach, where half the cost of control is assigned to the methane reduction and half to the VOC reduction. The results are presented separately for diaphragm and piston pumps. These values assume that the control device or VRU is installed solely for the purpose of controlling the emissions from a single natural gas-driven pneumatic pump, and only the emission reductions from a single pump are considered.
      For diaphragm pumps in the production segment using the single pollutant approach, the cost effectiveness is estimated to be $7,500 per ton of methane reduced using a new combustion device, and $8,500 using a new VRU ($8,300 with savings). For VOC, these cost effectiveness values are $26,900 per ton of VOC reduced using a new combustion device, and $30,400 using a new VRU ($29,800 with savings). These values are outside of the range considered reasonable by the EPA for both methane and VOC.
      For diaphragm pumps in the production segment using the multipollutant approach, the cost effectiveness is estimated to be $3,750 per ton of methane reduced using a new combustion device, and $4,250 using a new VRU ($4,150 with savings). For VOC, these cost effectiveness values are $13,450 per ton of VOC reduced using a new combustion device, and $15,200 using a new VRU ($14,900 with savings). These values are outside of the range considered reasonable by the EPA for both methane and VOC.
      For piston pumps in the production segment using the single pollutant approach, the cost effectiveness is estimated to be $68,100 per ton of methane reduced using a combustion device, and $77,000 using a VRU ($76,800 with savings). For VOC, these cost effectiveness values are $244,800 per ton of VOC reduced using a combustion device, and $2.5 million using a VRU (with and without savings). These values are outside of the range considered reasonable by the EPA for both methane and VOC.
      For piston pumps in the production segment using the multipollutant approach, the cost effectiveness is estimated to be $34,000 per ton of methane reduced using a combustion device, and $38,500 using a VRU ($38,400 with savings). For VOC, these cost effectiveness values are $122,400 per ton of VOC reduced using a combustion device, and $1.3 million using a VRU (with and without savings). These values are outside of the range considered reasonable by the EPA for both methane and VOC.
      For diaphragm pumps in the transmission and storage segment using the single pollutant approach, the cost effectiveness is estimated to be $7,400 per ton of methane reduced using a new combustion device, and $8,500 using a new VRU. For VOC, these cost effectiveness values are $270,000 per ton of VOC reduced using a new combustion device, and $305,000 using a new VRU. These values are outside of the range considered reasonable by the EPA for both methane and VOC.
      For diaphragm pumps in the transmission and storage segment using the multipollutant approach, the cost effectiveness is estimated to be $3,700 per ton of methane reduced using a new combustion device, and $4,200 using a new VRU. For VOC, these cost effectiveness values are $135,000 per ton of VOC reduced using a new combustion device, and $152,500 using a new VRU. These values are outside of the range considered reasonable by the EPA for both methane and VOC.
      For piston pumps in the transmission and storage segment using the single pollutant approach, the cost effectiveness is estimated to be $68,000 per ton of methane reduced using a combustion device, and $77,000 using a VRU. For VOC, these cost effectiveness values are $2.5 million per ton of VOC reduced using a combustion device, and $2.8 million using a VRU. These values are outside of the range considered reasonable by the EPA for both methane and VOC.
      For piston pumps in the transmission and storage segment using the multipollutant approach, the cost effectiveness is estimated to be $34,000 per ton of methane reduced using a combustion device, and $378,500 using a VRU. For VOC, these cost effectiveness values are $1.25 million per ton of VOC reduced using a combustion device, and $1.4 million using a VRU. These values are outside of the range considered reasonable by the EPA for both methane and VOC.
      For diaphragm pumps, we do not consider the costs to be reasonable to install a new control device, or a new VRU to route the emissions to a process, for the production and transmission and storage segments for methane or VOC emission reduction using either the single pollutant or multipollutant approach. Similarly, for piston pumps, we do not consider the costs to be reasonable under any scenario. Therefore, we are unable to conclude that requiring the installation of a new control device, or the installation of a new VRU to route emissions to a process, to achieve 95 percent reduction of methane and VOC emissions from natural gas-driven pumps for the production or transmission segments represents BSER in this proposal.
      Routing to an existing combustion device or VRU. In addition to evaluating the installation of a new control device or new VRU installed solely for the purpose of reducing the emissions from a single natural gas-driven pneumatic pump, we also evaluated the option of routing the emissions from natural gas-driven pneumatic pumps to an existing control device to achieve a 95 percent reduction in methane and VOC emissions or routing the emissions to an existing VRU and to a process. The emission reduction for this option would be the same as discussed above for a new control device achieving 95 percent control, that is 3.29 tpy of methane and 0.91 tpy of VOC per diaphragm pump, and 0.36 tpy methane and 0.10 tpy VOC per piston pump in the production segment and 3.29 tpy of methane and 0.09 tpy of VOC per diaphragm pump, and 0.36 tpy of methane and 0.01 ton per year of VOC per piston pump in the transmission and storage segment. The resulting cost effectiveness estimates for use of an existing control device to reduce emissions from natural gas-driven pumps in the production segment by 95 percent, or the use of an existing VRU to route emissions to a process, are discussed below under both the single pollutant approach, where all the costs are assigned to the reduction of one pollutant, and the multipollutant approach, where half the cost of control is assigned to the methane reduction and half to the VOC reduction. The results are presented separately for diaphragm and piston pumps.
      We estimated the costs for routing emissions to an existing control device or VRU based on the average of the cost presented in the 2015 proposed NSPS OOOOa and the costs presented by two commenters to the proposal, as documented in the 2016 NSPS OOOOa TSD. This yielded a capital cost estimate of $6,100 in 2019 dollars, for an annualized cost of $900 in 2019 dollars, using the 7 percent discount rate and 10-year equipment life. In the 2016 NSPS OOOOa TSD the EPA assumed there were no incremental operating costs for routing to an existing control device or VRU, so the total annual costs consist only of the $900 capital recovery cost. This assumption is maintained for this analysis. The same savings discussed above for the gas that is recovered by a VRU would be realized when routing to an existing VRU and to a process. These savings are $600 per year per diaphragm pump and $65 per year per piston pump in the production segment. The resulting annual costs for routing to an existing VRU and to process, considering these savings, are $270 per diaphragm pump and $340 per piston pump in the production segment. As noted above, transmission and storage facilities do not own the natural gas; therefore, savings from reducing the amount of natural gas emitted/lost was not applied for this segment.  
      For diaphragm pumps in the production segment using the single pollutant approach, the cost effectiveness is estimated to be $260 per ton of methane reduced using an existing combustion device, and $260 per ton of methane using an existing VRU ($80 with savings). For VOC, these cost effectiveness values are $950 per ton of VOC reduced using an existing combustion device, and $950 using an existing VRU ($300 with savings). For diaphragm pumps in the production segment using the multipollutant approach, the cost effectiveness is estimated to be $130 per ton of methane reduced using an existing combustion device, and $130 using an existing VRU ($40 with savings). For VOC, these cost effectiveness values are $475 per ton of VOC reduced using an existing combustion device, and $475 using an existing VRU ($150 with savings). These values are well within the range of what the EPA considers to be reasonable for methane and VOC using both the single pollutant and multipollutant approaches.
      For diaphragm pumps in the transmission and storage segment using the single pollutant approach, the cost effectiveness is estimated to be $260 per ton of methane reduced using an existing combustion device, and $260 using an existing VRU. For VOC, these cost effectiveness values are $950 per ton of VOC reduced using an existing combustion device, and $950 using an existing VRU. For diaphragm pumps in the transmission and storage segment using the multipollutant approach, the cost effectiveness is estimated to be $130 per ton of methane reduced using an existing combustion device, and $130 using an existing VRU. For VOC, these cost effectiveness values are $490 per ton of VOC reduced using an existing combustion device, and $490 using an existing VRU. These values are well within the range of what the EPA considers to be reasonable for methane and VOC using both the single pollutant and multipollutant approaches.
      The 2016 NSPS OOOOa requires that emissions from natural gas driven pneumatic pumps at well sites achieve a 95 percent reduction in methane and VOC emissions by routing them to a control device if an existing control device is on site. Owners and operators at well sites have successfully met this standard. Further, several state agencies (e.g,, California, proposed in New Mexico) have rules that include this requirement, and have extended the requirement to sites throughout the production segment as well as the transmission and storage segment. These factors considered together demonstrate the reasonableness of a requirement that emissions from natural gas driven pneumatic pumps at sites without access to electricity achieve a 95 percent reduction in methane and VOC emissions by routing them to a control device, provided that an existing control device is on site.
      The EPA concludes that the cost effectiveness of routing emissions from diaphragm pumps in the production and transmission and storage segments to an existing control device to achieve 95 percent reduction in methane and VOC, or in routing the emissions to a VRU and to a process, are reasonable. 
      There are secondary impacts from the use of a combustion device to control emissions routed from natural gas-driven pumps. The combustion of the recovered natural gas creates secondary emissions of hydrocarbons, NOx, CO2, and CO. The EPA considers the magnitude of these emissions to be reasonable given the significant reduction in methane and VOC emissions that the control would achieve. Details of these impacts are provided in the Technical Support Document for this rulemaking. There are no other wastes created or wastewater generated. The secondary impacts from use of a VRU are indirect, variable, and dependent on the electrical supply used to power the VRU. No other secondary impacts are expected.  
      In light of the above, we find that the BSER for reducing methane and VOC emissions from natural gas-driven diaphragm pumps in the production and transmission and storage segments is to route the emissions to an existing control device that achieves 95 percent control of methane and VOC, or to route the emissions to an existing VRU and to a process. We are, therefore, proposing to include this requirement in NSPS OOOOb. 
      For piston pumps in the production segment using the single pollutant approach, the cost effectiveness is estimated to be $2,400 per ton of methane reduced using a combustion device, and $2,400 using a VRU ($2,200 with savings). For VOC, these cost effectiveness values are $8,700 per ton of VOC reduced using a combustion device, and $8,700 using a VRU ($8,000 with savings).
      For piston pumps in the production segment using the multipollutant approach, the cost effectiveness is estimated to be $1,200 per ton of methane reduced using a combustion device, and $1,200 using a VRU ($1,100 with savings). For VOC, these cost effectiveness values are $4,350 per ton of VOC reduced using a combustion device, and $4,350 using a VRU ($4,000 with savings).
      For piston pumps in the transmission and storage segment using the single pollutant approach, the cost effectiveness is estimated to be $2,400 per ton of methane reduced using a combustion device, and $2,400 using a VRU. For VOC, these cost effectiveness values are $87,000 per ton of VOC reduced using a combustion device, and $87,000 using a VRU.
      For piston pumps in the transmission and storage segment using the multipollutant approach, the cost effectiveness is estimated to be $1,200 per ton of methane reduced using a combustion device, and $1,200 using a VRU. For VOC, these cost effectiveness values are $43,500 per ton of VOC reduced using a combustion device, and $43,500 using a VRU. 
      For piston pumps in the production segment, we do not consider the costs to route emissions from a natural gas-driven pneumatic pump to an existing control device to achieve 95 percent reduction, or to route to an existing VRU and to a process, to be reasonable for methane or VOC using the single pollutant approach or for methane for the multipollutant approach. While the VOC cost effectiveness using the multipollutant method is within the range that the EPA has previously considered reasonable, we do not believe that this should override the fact that the cost effectiveness values are unreasonable for all other scenarios. For piston pumps in the transmission and storage segment, we do not consider the costs reasonable to route emissions from a natural gas-driven pneumatic pump to an existing control device, or to route to an existing VRU and to a process, to be reasonable under any scenario. Therefore, we are unable to conclude that requiring the routing of emissions from natural gas-driven piston pumps in the production and transmission and storage segments to an existing control device to achieve 95 percent reduction of methane and VOC emissions, or the routing of emissions to a VRU and to a process, represents BSER for NSPS OOOOb in this proposal.
2. EG OOOOc
      The EPA evaluated BSER for the control of methane from existing pneumatic pumps (designated facilities) in all segments in the Crude Oil and Natural Gas source category covered by the proposed NSPS OOOOb and translated the degree of emission limitation achievable through application of the BSER into a proposed presumptive standard for these facilities that essentially mirrors the proposed NSPS OOOOb.
      First, based on the same criteria and reasoning as explained above, the EPA is proposing to define the designated facility in the context of existing pneumatic pumps as those that commenced construction on or before the publication date of this proposed rule (or can we put the marker here for OFR to insert the publication date). Based on information available to the EPA, we did not identify any factors specific to existing sources that would indicate that the EPA should alter this definition as applied to existing sources. Next, the EPA finds that the controls evaluated for new sources for NSPS OOOOb are appropriate for consideration for existing sources under the EG OOOOc. The EPA finds no reason to evaluate different, or additional, control measures in the context of existing sources because the EPA is unaware of any control measures, or systems of emission reduction, for pneumatic pumps that could be used for existing sources but not for new sources. Next, the methane emission reductions expected to be achieved via application of the control measures identified above to new sources are also expected to be achieved by application of the same control measures to existing sources. The EPA finds no reason to believe that these calculations would differ for existing sources as compared to new sources because the EPA believes that the baseline emissions of an uncontrolled source are the same, or very similar, and the efficiency of the control measures are the same, or very similar, compared to the analysis above. This is also true with respect to the costs, non-air environmental impacts, energy impacts, and technical limitations discussed above for the control options identified.
      The EPA has not identified any costs associated with applying these controls at existing sources, such as retrofit costs, that would apply any differently than, or in addition to, those costs assessed above regarding application of the identified controls to new sources. Considering savings, the cost effectiveness values for the proposed presumptive standard of zero emissions from pneumatic pumps in the natural gas processing sector range from $420 to $1,470 per ton of methane eliminated ($240 to $1,300 per ton considering savings). For diaphragm pumps in the production segment the cost effectiveness of the proposed presumptive standard is estimated to be $260 per ton of methane reduced using an existing (on site) combustion device or VRU, and $800 per ton of methane using an existing (on site) VRU ($80 with savings). For diaphragm pumps in the transmission and storage segment the cost effectiveness of the proposed presumptive standard is estimated to be $260 per ton of methane reduced using an existing (on site) combustion device, and $260 using an existing (on site) VRU. 
      In summary, the EPA did not identify any factors specific to existing sources, as opposed to new sources, that would alter the analysis above for the proposed NSPS OOOOb as applied to the designated pollutant (methane) and the designated facilities (pneumatic pumps). As a result, the proposed presumptive standards for existing pneumatic pumps are as follows.
      For pneumatic pumps in the production and transmission and storage segments, the presumptive standard is routing emissions to an existing (already on site) control device or existing (already on site) VRU and to a process to achieve 95 percent reduction in methane. For pneumatic pumps in the natural gas processing sector, the presumptive standard is a natural gas emission rate of zero. 
      As for new sources, the EPA is specifically soliciting comment on whether the production and transmission storage segments should be subcategorized based on the availability of electricity and BSER determined separately for each subcategory in the EG.
H. Proposed Standards for Equipment Leaks at Natural Gas Processing Plants 
1. NSPS OOOOb
a. Background
In the 2012 NSPS OOOO, the EPA established VOC standards for equipment leaks at onshore natural gas processing plants. These standards were based on the Standards of Performance for Equipment Leaks of VOC in the Synthetic Organic Chemicals Manufacturing Industry (NSPS VVa), which is an EPA Method 21 LDAR program generally requiring monthly monitoring of pumps with a leak definition of 2,000 ppm, quarterly monitoring of valves with a leak definition of 500 ppm, and annual monitoring of connectors with a leak definition of 500 ppm. In the 2016 NSPS OOOOa, the EPA added GHG (methane) to the title of the standards for equipment leaks at onshore natural gas plants but continued to rely on the requirements in NSPS VVa, which limited monitoring and repair (if found leaking) to those equipment components "in VOC service." Based on our review of the current standards, we are proposing to revise the equipment leak standards for onshore natural gas plants to more readily apply to equipment components that have the potential to emit methane even though they are not "in VOC service." 
b. Technology and LDAR Program Review
The EPA acknowledges that advancements are being made in leak detection, including remote sensing, sensor networks, and OGI. The EPA already provides use of OGI as an alternative work practice at 40 CFR 60.18(g); however, the alternative work practice requires annual EPA Method 21 monitoring as part of the OGI monitoring protocol. Parallel with this proposal, the EPA is proposing Appendix K to part 60 to provide a standard method for OGI leak monitoring. This allows us to consider a wider range of LDAR programs when evaluating the BSER for equipment leaks at onshore natural gas processing plants. To evaluate different LDAR programs, we used a Monte Carlo simulation that simulated initiation of leaks for pumps, valves, and connectors at monthly intervals based on component specific leak frequencies and EPA Method 21 leak size distributions based on historical EPA Method 21 leak data. We randomly assigned a mass emission rate based on the EPA Method 21 leak size assuming a lognormal distribution for the mass emission rate around the EPA Method 21 screening value correlation equation estimates. The simulation runs for five years for each LDAR program to build up leaks that might not be repaired under a given program, and compares the emissions estimated in the fifth year of the simulation for different LDAR programs. The model also records the number of repairs made in the fifth year of the simulation to assess the annual repair costs associated with the LDAR program. More information on the LDAR program Monte Carlo simulation and associated cost analyses is available in the Technical Support Document for this proposal. 
Based on our model simulation of NSPS OOOOa requirements (Method 21 based LDAR program following the requirements in NSPS VVa), the EPA projects that the program achieves a 91.5 percent emission reduction for the components monitored. This is comparable to the projected control efficiencies of this LDAR program applied to similar industrial processes. However, when considering the components not monitored at the onshore natural gas processing plant because they are not "in VOC service", the overall hydrocarbon control efficiency of the current NSPS OOOOa requirements drops to 73.2 percent. Thus, significant emission reductions can be achieved by extending the current provisions to include all components that have the potential to emit methane. 
Based on our model simulation of an OGI-based LDAR program, we found that bimonthly OGI monitoring of all equipment components (with potential VOC or methane emissions) using devices capable of identifying mass leaks at 30 g/hr and at 15 g/hr would achieve emission reductions of 88.5 percent and 92.2 percent, respectively. Based on the requirements in Appendix K that the instrument be able to detect a methane leak of 17 g/hr, these results suggest that bimonthly OGI monitoring following Appendix K will achieve comparable emission reductions as the current NSPS OOOOa requirements for the equipment components subject to the monitoring requirements. 
c. Control Options and BSER Analysis
The EPA then evaluated various LDAR programs for their control efficiency, cost and cost effectiveness for a small and a large model natural gas processing plant. We considered the (option 1) current NSPS OOOOa standards expanded to components that also have the potential to emit methane regardless of the VOC content of the stream, (option 2) bimonthly OGI following Appendix K for all components (VOC or methane), and (options 3 and 4) a hybrid approach following the current alternative work practice (bimonthly OGI with annual EPA Method 21). For options 3 and 4 we evaluated requiring an annual EPA Method 21 survey at 10,000 ppm and 500 ppm, respectively. These control options and their associated costs are summarized in Tables 18 and 19 for the small and large model plants, respectively. 
                                       
    TABLE 18. SUMMARY OF CONTROL OPTIONS AND COSTS FOR SMALL MODEL PLANTS 
                                Control Option
                           Emissions Reduction (tpy)
                               Capital Cost ($)
                              Annual Cost ($/yr)
                               CE[a] ($/ton VOC)
                             CE[a] ($/ton Methane)
                            Incremental ($/ton VOC)
                          Incremental ($/ton Methane)
                                       
                                     VOC 
                                   Methane 
                                       
                                       
                                       
                                       
                                       
                                       
                            Methane and VOC Service
1
                                                                          12.34
                                                                          56.95
                                                                        $17,700
                                                                       $114,100
                                                                         $9,200
                                                                         $2,000
                                                                             --
                                                                             --
2
                                                                          12.61
                                                                          58.19
                                                                         $1,500
                                                                        $62,800
                                                                         $5,000
                                                                         $1,100
                                                                      -$189,100
                                                                       -$41,300
3
                                                                          12.64
                                                                          58.33
                                                                        $19,200
                                                                        $84,500
                                                                         $6,700
                                                                         $1,400
                                                                       $696,200
                                                                       $151,100
4
                                                                          12.76
                                                                          58.92
                                                                        $19,200
                                                                        $95,500
                                                                         $7,500
                                                                         $1,600
                                                                        $87,000
                                                                        $18,800

    TABLE 19. SUMMARY OF CONTROL OPTIONS AND COSTS FOR LARGE MODEL PLANTS 
                                Control Option
                           Emissions Reduction (tpy)
                               Capital Cost ($)
                              Annual Cost ($/yr)
                               CE[a] ($/ton VOC)
                             CE[a] ($/ton Methane)
                            Incremental ($/ton VOC)
                          Incremental ($/ton Methane)
                                       
                                     VOC 
                                   Methane 
                                       
                                       
                                       
                                       
                                       
                                       
                            Methane and VOC Service
1
                                                                          25.59
                                                                         118.27
                                                                        $36,200
                                                                       $229,000
                                                                         $9,000
                                                                         $1,900
                                                                             --
                                                                             --
2
                                                                          26.11
                                                                         120.81
                                                                         $3,000
                                                                       $123,500
                                                                         $4,700
                                                                         $1,000
                                                                      -$200,000
                                                                       -$43,100
3
                                                                          26.17
                                                                         121.10
                                                                        $39,200
                                                                       $170,500
                                                                         $6,500
                                                                         $1,400
                                                                       $760,000
                                                                       $165,200
4
                                                                          26.44
                                                                         122.31
                                                                        $39,200
                                                                       $191,300
                                                                         $7,200
                                                                         $1,600
                                                                        $79,500
                                                                        $17,100

We further assumed that all facilities outsource their equipment leak surveys. The first year "capital" costs of implementing an EPA Method 21 program (identifying components required to be monitored and developing a data system to track the proper frequency to monitor each component) are summarized in Tables 18 and 19. Additionally, these tables summarize the annualized costs of conducting a complete EPA Method 21 monitoring survey of all equipment (those in VOC service or contacting methane), which includes the annual costs of conducting required surveys and making the necessary repairs as well as annualized first year "capital" costs. The first-year startup costs for OGI surveys are small, estimated to be $750 for small plants and $1,500 for large plants. Because OGI surveys can be conducted much more quickly, the annualized cost of conducting bimonthly OGI surveys is approximately half the cost of EPA Method 21 surveys through NSPS VVa. Both EPA Method 21 and OGI LDAR programs reduce loss of product. Therefore, the costs of the LDAR programs are offset to some degree to the emissions reduced. When evaluating LDAR programs that consider all components (both VOC and methane), the annual value of the product not lost due to reduced emissions is approximately $14,000/yr.
Based on our analysis, the resulting cost effectiveness is reasonable for all of the options when assigning all costs to the reduction of methane. When assigning all costs to VOC reduction, however, only the bimonthly OGI option is considered reasonable at $5,000/ton VOC reduced for small plants and $4,700/ton VOC reduced at large plants. The EPA next considered the incremental cost-effectiveness between the four options to determine which option represents the BSER for equipment leaks at onshore natural gas processing plants. All four options achieve similar emission reductions, as discussed in the previous section. Bimonthly OGI (option 2) reduces an additional 2 tpy of methane at a cost savings. Adding annual EPA Method 21, at either 10,000 ppm or 500 ppm reduces an additional 1.5 tpy methane but at significant cost well above any costs the EPA would consider appropriate, at almost $700,000/ton methane reduced. Therefore, the EPA does not consider it reasonable to require the additional of annual EPA Method 21 at either leak definition. 
Based on the discussion above, we consider a bimonthly OGI LDAR program following Appendix K that includes all equipment components that have the potential to emit VOC or methane to be BSER for new sources. Therefore, we are proposing this LDAR requirement for new sources under NSPS OOOOb. Because an EPA Method 21 monitoring program based on the requirements of NSPS VVa when applied to all equipment components that have the potential to emit VOC or methane is projected to achieve similar emission reductions, we are proposing that this EPA Method 21-based LDAR program may be used as an alternative to bimonthly OGI surveys. 
In the development of the 2012 NSPS OOOO, we found that NSPS VVa provisions for PRDs, open-ended valves or lines, and closed vent systems and equipment designated with no detectable emissions were BSER. Available information since then continues to support this conclusion. Therefore, we are proposing to retain the current requirements in the 2016 NSPS OOOOa (which incorporates by reference specific provisions NSPS VVa) for PRDs, open-ended valves or lines, and closed vent systems and equipment designated with no detectable emissions, except expanding the applicability to sources that have the potential to emit methane. The EPA is soliciting information that would support the use of the proposed bimonthly OGI monitoring requirement for these equipment components in place of the NSPS VVa annual EPA Method 21 monitoring.
The EPA requests comments on ways to streamline approval of alternative LDAR programs using remote sensing techniques, sensor networks, or other alternatives for equipment leaks at onshore natural gas processing plants. Based on our Monte Carlo equipment leak model that assumes well-implemented LDAR programs with no delayed repair, both an EPA Method 21 based program following NSPS VVa and a bimonthly OGI monitoring program following Appendix K are projected to achieve a 91-percent emission reduction effectiveness. We request comment on whether providing such an emission reduction target and equipment leak modeling tool to simulate LDAR under similar "ideal" program implementation conditions may facilitate future equivalency determinations.  
2. EG OOOOc
      The application of an LDAR program at an existing source is the same as at a new source because there is no need to retrofit equipment at the site to achieve compliance with the work practice standard. The cost effectiveness for implementing a bimonthly OGI LDAR program for all equipment components that have the potential to emit methane is approximately $850/ton methane reduced. As explained above, the cost effectiveness of this OGI monitoring option is within the range of costs we believe to be reasonable for methane reductions. Therefore, we consider a bimonthly OGI LDAR program following Appendix K that includes all equipment components that have the potential to emit methane to be BSER for existing sources.
I. Proposed Standards for Well Completions
a. Background
      Pursuant to CAA section 111(b)(1)(B), the EPA reviewed the current standards in NSPS OOOOa for well completions and proposes to determine that they continue to reflect the BSER for reducing methane and VOC emissions during oil and natural gas well completions following hydraulic fracturing and refracturing. Accordingly, we are not proposing revisions to these standards. Provided below are a description of the affected facilities, the current standards, and a summary of our review.
	Natural gas and oil wells all must be "completed" after initial drilling in preparation for production. Well completion activities not only will vary across formations but can vary between wells in the same formation. Over time, completion and recompletion activities may change due to the evolution of well characteristics and technology advancement. Well completion activities include multiple steps after the well bore hole has reached the target depth. Developmental wells are drilled within known boundaries of a proven oil or gas field and are located near existing well sites where well parameters are already recorded and necessary surface equipment is in place. When drilling occurs in areas of new or unknown potential, well parameters such as gas composition, flow rate, and temperature from the formation need to be ascertained before surface facilities required for production can be adequately sized and brought on site. In this instance, exploratory (also referred to as "wildcat") wells and field boundary delineation wells typically either vent or combust the flowback gas.
One completion step for improving oil and gas production is to fracture the reservoir rock with very high-pressure fluid, typically a water emulsion with a proppant (generally sand) that "props open" the fractures after fluid pressure is reduced. Natural gas emissions are a result of the backflow of the fracture fluids and reservoir gas at high pressure and velocity necessary to clean and lift excess proppant to the surface. Natural gas from the completion backflow escapes to the atmosphere during the reclamation of water, sand, and hydrocarbon liquids during the collection of the multi-phase mixture directed to a surface impoundment. As the fracture fluids are depleted, the backflow eventually contains a higher volume of natural gas from the formation. Due to the specific additional equipment and resources involved and the nature of the backflow of the fracture fluids, completions involving hydraulic fracturing have higher costs and vent substantially more natural gas than completions not involving hydraulic fracturing.
During its lifetime, wells may need supplementary maintenance, referred to as recompletions (these are also referred to as workovers). Recompletions are remedial operations required to maintain production or minimize the decline in production. Examples of the variety of recompletion activities include completion of a new producing zone, re-fracture of a previously fractured zone, removal of paraffin buildup, replacing rod breaks or tubing tears in the wellbore, and addressing a malfunctioning downhole pump. During a recompletion, portable equipment is conveyed back to the well site temporarily and some recompletions require the use of a service rig. As with well completions, recompletions are highly specialized activities, requiring special equipment, and are usually performed by well service contractors specializing in well maintenance. Any flowback event during a recompletion, such as after a hydraulic fracture, will result in emissions to the atmosphere unless the flowback gas is captured.
When hydraulic re-fracturing (recompletions) is performed, the emissions are essentially the same as new well completions involving hydraulic fracture, except that surface gas collection equipment will already be present at the wellhead after the initial fracture. The flowback velocity during re-fracturing will typically be too high for the normal wellhead equipment (separator, dehydrator, lease meter), while the production separator is not typically designed for separating sand.
Flowback emissions are a result of free gas being produced by the well during well cleanup event, when the well also happens to be producing liquids (mostly water) and sand. The high rate flowback, with intermittent slugs of water and sand along with free gas, is directed to an impoundment or vessels until the well is fully cleaned up, where the free gas vents to the atmosphere while the water and sand remain in the impoundment or vessels. Therefore, nearly all of the flowback emissions originate from the recompletion process but are vented as the flowback enters the impoundment or vessels. Minimal amounts of emissions are caused by the fluid (mostly water) held in the impoundment or vessels since very little gas is dissolved in the fluid when it enters the impoundment or vessels.
	The 2021 GHGI estimates approximately 19,800 metric tpy of methane emissions from hydraulically fractured natural gas wells and approximately 9,900 metric tpy of methane emissions from hydraulically fractured oil wells in 2019.
b. Affected Facility
	Each affected facility is a single well that conducts a well completion operation following hydraulic fracturing or refracturing.
c. Current NSPS Requirements
	The current NSPS for natural gas and oil well completions and recompletions are the same. For well completions of hydraulically fractured (or refractured) wells, the EPA identified two subcategories of hydraulically fractured wells for which well completions are conducted: (1) non-wildcat and non-delineation wells (subcategory 1 wells); and (2) wildcat and delineation wells and low-pressure wells (subcategory 2 wells). A wildcat well, also referred to as an exploratory well, is a well drilled outside known fields or is the first well drilled in an oil or gas field where no other oil and gas production exists. A delineation well is a well drilled to determine the boundary of a field or producing reservoir. 
	In the 2016 NSPS OOOOa rule, the EPA finalized operational standards for non-wildcat and non-delineation wells (subcategory 1 wells) that required a combination of REC and combustion. Because RECs are not feasible for every well at all times during completion or recompletion activities due to variability of produced gas pressure and/or inert gas concentrations, the rule allows for wellhead owners and operators to continue to reduce emissions when RECs are not feasible due to well characteristics (e.g., wellhead pressure or inert gas concentrations) by using a completion combustion device. For wildcat and delineation wells and low-pressure wells (subcategory 2 wells), the EPA finalized an operational standard that required either (1) routing all flowback directly to a completion combustion device with a continuous pilot flame (which can include a pit flare) or, at the option of the operator, (2) routing the flowback to a well completion vessel and sending the flowback to a separator as soon as a separator will function and then directing the separated gas to a completion combustion device with a continuous pilot flame. For option 2, any gas in the flowback prior to the point when the separator will function was not subject to control. For both options (1) and (2), combustion is not required in conditions that may result in a fire hazard or explosion, or where high heat emissions from a completion combustion device may negatively impact tundra, permafrost, or waterways. Under the 2016 NSPS OOOOa rule, oil wells with a gas-to-oil ratio less than 300 scf of gas per stock tank barrel of oil produced are affected facilities but have no requirements other than to maintain records of the low GOR certification and a claim signed by the certifying official.
d. 2021 BSER Analysis
	The two techniques considered under the previous BSER analyses that have been proven to reduce emissions from production segment well completions and recompletions include REC and completion combustion. REC is an approach that not only reduces emissions but delivers natural gas product to the sales meter that would typically be vented. The second technique, completion combustion, destroys the organic compounds. No other emissions control techniques were identified as being required under other rules (Federal, state, or local rules) that would exceed the level of control required under the 2016 NSPS OOOOa rule. Therefore, no other technology control requirements were evaluated in this review.
      Reduced emission completions, also referred to as "green" or "flareless" completions, use specially designed equipment at the well site to capture and treat gas so it can be directed to the sales line. This process prevents some natural gas from venting and results in additional economic benefit from the sale of captured gas and, if present, gas condensate. However, as the EPA has previously acknowledged, there are some limitations that may exist for performing RECs based on technical barriers. These limitations continue to exist. Three main limitations for performing a REC include the proximity of pipelines to the well, the pressure of the produced gas, and the inert gas concentration. These limitations are discussed below.
      For exploratory wells (in particular), no nearby sales line may exist. The lack of a nearby sales line incurs higher capital outlay risk for exploration and production companies and/or pipeline companies constructing lines in exploratory fields. 
      During the completion/recompletion process, the pressure of flowback fluids may not be sufficient to overcome the gathering line backpressure. In this case, combustion of flowback gas is one option, either for the duration of the flowback or until a point during flowback when the pressure increases to flow to the sales line. Another potential compressor application is to boost pressure of the flowback gas after it exits the separator. This technique is experimental because of the difficulty operating a compressor where there is a widely fluctuating flowback rate.
      Lastly, if the concentration of inert gas, such as nitrogen or CO2, in the flowback gas exceeds sales line concentration limits, venting to the atmosphere or to a combustion device of the flowback may be necessary for the duration of flowback or until the gas energy content increases to allow flow to the sales line. Further, since the energy content of the flowback gas may not be high enough to sustain a flame due to the presence of the inert gases, combustion of the flowback stream would require a continuous ignition source with its own separate fuel supply.
	Where a REC can be conducted, the achievable emission reductions vary according to reservoir characteristics and other parameters including length of completion, number of fractured zones, pressure, gas composition, and fracturing technology/technique. Based on several experiences presented at Natural Gas STAR technology transfer workshops, this analysis assumes 90 percent of flowback gas can be recovered during a REC. Any amount of gas that cannot be recovered can be directed to a completion combustion device in order to achieve a minimum 95 percent reduction in emissions.
      Completion combustion devices commonly found on drilling sites are generally crude and portable, often installed horizontally due to the liquids that accompany the flowback gas. These flares can be as simple as a pipe with a basic ignition mechanism and discharge over a pit near the wellhead. However, the flow directed to a completion combustion device may or may not be combustible depending on the inert gas composition of flowback gas, which would require a continuous ignition source. Sometimes referred to as pit flares, these types of combustion devices do not employ an actual control device and are not capable of being tested or monitored for efficiency. They do provide a means of minimizing vented gas and is preferable to venting.
      The efficiency of completion combustion devices, or exploration and production flares, can be expected to achieve 90 percent, on average, over the duration of the completion or recompletion. If the energy content of natural gas is low, then the combustion mechanism can be extinguished by the flowback gas. Therefore, it is more reliable to install an igniter fueled by a consistent and continuous ignition source. Because of the exposed flame, open pit flaring can present a fire hazard or other undesirable impacts in some situations (e.g., dry, windy conditions and proximity to residences). As a result, owners and operators may not be able to combust unrecoverable gas safely in every case. 
Noise and heat are the two adverse impacts of completion combustion device operations. In addition, combustion and partial combustion of many pollutants also create secondary pollutants including NOx, CO, sulfur oxides (SOx), CO2, and smoke/particulates. The degree of combustion depends on the rate and extent of fuel mixing with air and the temperature maintained by the flame. Most hydrocarbons with carbon-to-hydrogen ratios greater than 0.33 are likely to smoke. The high methane content of the gas stream routed to the completion combustion device, it suggests that there should not be smoke except in specific circumstances (e.g., energized fractures). The stream to be combusted may also contain liquids and solids that will also affect the potential for smoke. 
      The previous BSER analyses cost effectiveness per ton of methane and VOC emissions reduced per completion event evaluated for REC, completion combustion, and REC and completion combustion were updated to 2019 dollars. The results of this updated analysis are provided below, and details are provided in the Technical Support Document for this rulemaking.
      The updated capital cost for performing a REC for a well completion or recompletion lasting 3 days is estimated to be $15,174 (2019 dollars). Monetary savings associated with additional gas captured to the sales line is estimated based on a natural gas price of $3.13 per Mcf. It was assumed that all gas captured would be included as sales gas. The updated capital and cost for wells including completion combustion devices resulted in an estimated average completion combustion device cost of approximately of $4,198 per well completion (2019 dollars). For both REC and completion combustion devices, the capital costs are one-time events, and annual costs were conservatively assumed to be equal to the capital costs. The EPA also evaluated the costs that would be associated with using a combination of a REC and completion combustion device. The annual costs would be a combined estimated capital and annual cost of $19,372 (2019 dollars). As a result of updating capital/annual costs to reflect 2019 dollars, and decreasing the control efficiency assumed for completion combustion from 95 percent to 90 percent, the cost effectiveness estimates are slightly higher, but substantially similar to previous cost effectiveness BSER analysis control option estimates for natural gas well and oil well completions and recompletions.
      For gas wells, under the single pollutant approach where all the costs are assigned to the reduction of methane emissions and zero to reduction of VOC, the cost effectiveness estimates were approximately $110 per ton of methane reduced for REC (net savings if revenue of the gas saved is considered), $30 for completion combustion, and $130 for a combination of REC and completion combustion (net savings if revenue of the gas saved is considered). If all costs were assigned to VOC reduction and zero to methane reduction, the cost effectiveness estimates were approximately $730 per ton of VOC removed for REC (net savings if revenue of the gas saved is considered), $200 for completion combustion, and $880 for a combination of REC and completion combustion (net savings if revenue of the gas saved is considered). Under the multipollutant approach where half the cost of control is assigned to the methane reduction and half to the VOC reduction, these estimates are approximately $50 per ton of methane reduced for REC (net savings if revenue of the gas saved is considered), $15 for completion combustion, and $64 for a combination of REC and completion combustion (net savings if revenue of the gas saved is considered). For VOC, the cost effectiveness estimates were approximately $360 per ton of VOC removed for REC (net savings if revenue of the gas saved is considered), $100 for completion combustion, and $440 for a combination of REC and completion combustion (net savings if revenue of the gas saved is considered).
      For oil wells, under the single pollutant approach where all the costs are assigned to the reduction of methane emissions and zero to reduction of VOC emissions, the cost effectiveness values were approximately $1,740 per ton of methane reduced for REC ($1,550 with natural gas savings), $480 for completion combustion, and $2,100 for a combination of REC and completion combustion ($1,900 with natural gas savings). Where all costs were assigned to reducing VOC emissions and zero to reducing methane emissions, the cost effectiveness estimates were approximately $2,070 per ton of VOC removed for REC ($1,850 with savings), $570 for completion combustion, and $2,500 for a combination of REC and completion combustion ($2,300 with natural gas savings). Under the multipollutant approach where half the cost of control is assigned to the methane reduction and half to the VOC reduction, these estimates are approximately $870 per ton of methane reduced for REC ($780 with natural gas savings), $240 for completion combustion, and approximately $1,050 for a combination of REC and completion combustion. For VOC, the cost effectiveness estimates were approximately $1,040 per ton of VOC removed for REC ($930 with natural gas savings), $290 for completion combustion, and $1,250 for a combination of REC and completion combustion ($1,150 with natural gas savings).
	As noted above, the current NSPS OOOOa requirements consist of a combination of REC and completion combustion for hydraulically fractured natural gas and oil well completions. These techniques have been employed by the oil and gas industry since 2012 for natural gas well completions and 2016 for oil well completions. The EPA concludes that the cost effectiveness of REC, completion combustion, or a combination, for gas wells are all within the range that the EPA considers to be reasonable. For oil wells, under the single pollutant approach, the cost effectiveness values are all within the ranges that the EPA considers reasonable, with the exception of the cost-effectiveness of controlling methane for oil wells from REC and combined REC and completion combustion. However, since there are multiple scenarios where the cost effectiveness of the measures is reasonable for oil wells (including the cost effectiveness of VOC for REC and combined REC and completion combustion), we conclude that the overall cost effectiveness is reasonable. 
      There are secondary impacts from the use of a completion combustion device, as the combustion of the gas creates secondary emissions of hydrocarbons, NOx, CO2, and CO. The EPA considers the magnitude of these emissions to be reasonable given the significant reduction in methane and VOC emissions that the control would achieve. Details of these impacts are provided in the Technical Support Document for this rulemaking. There are no other wastes created or wastewater generated from either REC or completion combustion.
      In light of the above, we determined that the current standards, which consist of a combination of REC and combustion, continue to represent the BSER for reducing methane and VOC emissions from well completions of hydraulically fractured or refractured oil and natural gas wells. We therefore propose to retain these standards in the proposed NSPS OOOOb. 
2. EG OOOOc
      A well completion operation following hydraulic fracturing or refracturing is a "modification," as defined in CAA section 111(a), as each such well completion operation involves a physical change to a well that results in an increase in emissions; accordingly, each such operation would trigger the applicability of the NSPS. Therefore, there are no "existing" well completion operations of hydraulically fractured or refractured oil or natural gas wells. In light of the above, there are no proposed presumptive standards for such operations in this action.  
J. Proposed Standards for Sweetening Units  
      Sulfur dioxide (SO2) standards for onshore sweetening units were first promulgated in 1985 and codified in 40 CFR part 60, subpart LLL (NSPS LLL). In 2012, the EPA reviewed the NSPS for the oil and natural gas sector, and the resulting 2012 NSPS OOOO rule incorporated provisions of NSPS LLL with minor revisions to adapt the NSPS LLL language to NSPS OOOO (77 FR 49489). The incorporated provisions required sweetening unit affected facilities to reduce SO2 emissions via sulfur recovery. The EPA also increased the SO2 emission reduction standard from the subpart LLL requirement for units with a sulfur production rate of at least 5 long tons per day (LT/D) from 99.8 percent to 99.9 percent. This change was based on the reanalysis of the original data used in the NSPS LLL BSER analysis. 
      In 2016, the EPA finalized the NSPS OOOOa rule  -  which established standards for both methane and VOCs for certain equipment, process and activities across the oil and natural gas sector. The final 2016 NSPS OOOOa rule reaffirmed and included the SO2 emission reduction requirements as specified in the 2012 NSPS OOOO rule (81 FR 35824).
      The EPA then amended the 2016 NSPS OOOOa rule in 2020 to correct an affected facility definition applicability error in the rule as it pertains to sweetening units. The 2016 NSPS OOOOa rule erroneously limited the applicability of the SO2 standards to sweetening units located at onshore natural gas processing plants. This limitation was not included in NSPS LLL, and no reason was identified as to "why the extraction of natural gas liquids relates in any way to the SO2 standards such that the standards should only apply to sweetening units located at onshore natural gas processing plants engaged in extraction or fractionation activities." (85 FR 57398) Therefore, the 2020 NSPS OOOOa final rule amendments corrected the affected facility description applicability error to correctly define affected facilities as any onshore sweetening unit that processes natural gas produced from either onshore or offshore wells at 40 CFR 60.5365a(g). 
      A sweetening unit refers to a process device that removes hydrogen sulfide (H2S) and/or carbon dioxide (CO2) from the sour natural gas stream (40 CFR 60.5430a)  -  i.e., sweetening units convert H2S in acid gases (i.e., H2S and CO2) that are separated from natural gas by a sweetening process, like amine gas treatment, into elemental sulfur in the Claus process. These units can operate anywhere within the production and processing segments of the oil and natural gas source category, including as stand-alone processing facilities that do not extract or fractionate natural gas liquids from field gas (85 FR 57408).
      An estimated 6,900 tons of SO2 emissions were reported under the National Emissions Inventory (NEI) for Year 2017 for Source Classification Code 31000201 (Industrial Processes Oil and Gas Production, Natural Gas Production, Gas Sweetening: Amine Process) and SCC 31000208 (Industrial Processes, Oil and Gas Production, Natural Gas Production, Sulfur Recovery Units).
 	Pursuant to CAA section 111(b)(1)(B), the EPA reviewed the current standards in NSPS OOOOa (including the 2020 revisions) for sweetening units and proposes to determine that they continue to reflect the BSER for reducing SO2 emissions. The EPA has not identified any greater emissions control level than what is currently required under NSPS OOOOa for sweetening unit affected facilities. Therefore, the EPA is proposing to retain/include the current NSPS OOOOa requirements for sweetening units for the control of SO2 emissions from sweetening unit affected facilities in NSPS OOOOb. The proposed NSPS OOOOb maintains the requirement that each sweetening unit that processes natural gas produced from either onshore or offshore wells is an affected facility; as well as each sweetening unit that processes natural gas followed by a sulfur recovery unit. Units with a sulfur production rate of at least 5 long tons per day must reduce SO2 emissions by 99.9 percent. Compliance with the standard is determined based on initial performance tests and daily reduction efficiency measurements. For affected facilities that have a design capacity less than 2 LT/D of H2S in the acid gas (expressed as sulfur), recordkeeping and reporting requirements are required; however, emissions control requirements are not required.  Facilities that produce acid gas that is entirely re-injected into oil/gas-bearing strata or that is otherwise not released to the atmosphere are also not subject to emissions control requirements. 
XIII. Solicitations for Comment on Additional Emission Sources and Definitions
      The EPA is considering including additional sources as affected facilities under the proposed NSPS OOOOb and the proposed EG OOOOc. Specifically, the EPA is evaluating the potential for establishing standards applicable to wells that produce associated gas, abandoned and unplugged wells, pipeline pigging and related blowdown activities, 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 propose NSPS and EG for these emissions sources. As described below, the EPA is soliciting information to assist in this effort.
      The EPA is also assessing whether proposed standards that would require 95 percent reduction based on a combustion control device as the BSER (e.g., standards for storage vessels, centrifugal compressors, and pneumatic pumps) could be further strengthened, including the potential for additional monitoring and associated recordkeeping and reporting requirements, to ensure proper design and operation of combustion control devices. While we are not proposing NSPS nor EG for these emissions sources (i.e., associated gas, abandoned wells, pigging operations, or tank truck loading) or updates to ensure proper design and operation of combustion control devices in this action, the EPA is soliciting comment and information that would better inform the EPA as we continue to evaluate options for these sources. Should the EPA receive information through the public comment process that would help the Agency evaluate BSER for these emission sources, the EPA could consider NSPS and EG for these sources through a supplemental proposal. In this section we summarize the available information that we have evaluated regarding emissions, control options, and where specific states may have existing requirements, and we solicit specific comments. In the case of combustion control devices, we solicit comment on the current standard of 95 percent reduction and what additional monitoring, recordkeeping, and reporting may be appropriate to ensure compliance. We also generally solicit comment and information on the following topics associated with these emission sources. 
      The EPA solicits comment on the control options discussed below and how these controls may be broadly applied across different basins or geographic areas. The EPA solicits comment on what equipment is onsite during these emission events. The EPA solicits comment on the technical feasibility of control options and any instances where it is not technically feasible to minimize emissions from these sources including, but not limited to, any retrofit concerns for existing sources. The EPA solicits comment on any practices owners and operators already implement as part of voluntary efforts or state requirements to minimize emissions from these sources. The EPA solicits comment on methods/approaches for estimating baseline emissions from these sources, estimating cost of control, and efficiency of control options. Finally, the EPA solicits comment on the cost of maintaining records and submitting reports for these emissions sources, including the types of records that are appropriate to maintain and report.  
A. Associated Gas
      Associated gas originates at wellheads that also produce hydrocarbon liquids and occurs either in a discrete gaseous phase at the wellhead or is released from the liquid hydrocarbon phase by separation. There are no current NSPS requirements for this emission source. Typically, the state oil and gas regulatory agencies (or, on certain public and tribal lands, the BLM) regulate venting and flaring of associated gas to ensure oil and natural gas resources are conserved and utilized in a manner consistent with their respective statutes. State oil and gas regulatory agencies typically encourage capture (conservation) over flaring, then flaring over venting. In addition, state regulators have adopted a variety of approaches for regulating venting and flaring. Some require technical and economic feasibility analyses for continuing flaring beyond a certain time (e.g., one year) but can approve waivers to continue flaring beyond that time. Some require gas capture plans to track and incrementally increase the percentage of gas captured (rather than flared) over prescribed timelines and some of these include provisions to curtail production in the event of not meeting gas capture goals. Some state regulations recognize that there are times when gas capture may not be feasible, such as when there is no gas gathering pipeline to tie into, the gas gathering pipeline may be at capacity, or a compressor station or gas processing plant downstream may be off-line, thus closing in the gas gathering pipeline. Venting may be allowed in certain circumstances such as emergency or upset conditions, during production evaluation, well purging or productivity tests. Although these rules typically require reporting of the volume of gas flared and vented (and sometimes gas analysis too), some states lump flaring and venting together in publicly-accessible well data. 
      Some flared gas contains components that if improperly combusted could cause air quality degradation and health issues, so it is important to ensure the flare is operating optimally. State oil and gas rules typically do not include monitoring, recordkeeping and reporting (MRR) on the performance of the flare and would not be recognized as providing legally and practicably enforceable limits for CAA purposes. Some state environmental regulators address associated gas with a regulation stipulating flaring over venting that includes MRR provisions, while others regulate flaring over venting without monitoring requirements. Some regulate flaring over venting with the MRR provisions as part of the air permit, and others yet do not regulate this source at all.
      If the EPA were to propose requirements addressing associated gas, it could affect new and existing sources (i.e., wells producing associated gas). The EPA's proposed BSER could also differentiate between new and existing sources since the feasibility and cost of certain control options (such as requiring capture or beneficial use of associated gas) could vary significantly across new and existing sources. 
      For new and existing sources, options to mitigate emissions from associated gas in order of environmental and resource conservation benefit could include:
 Capturing the associated gas from the separator and routing into a gas gathering flow line or collection system;
 Beneficially using the associated gas (e.g., onsite use, natural gas liquid processing, electrical power generation, gas to liquid);
 Reinjecting for enhanced oil recovery;
 Curtailing oil production until gas capture or beneficial use can occur; and
 Flaring with legally and practicably enforceable limits.
      Related to the last option above, enhancing monitoring and performance requirements for flares at existing sources may be an important emissions reduction measure. For those operators who have already installed monitoring capability on their existing flares, the additional investment may be minimal to cover reporting of performance. For those existing sources who do not have flare monitoring installed, the EPA solicits comment both on the flare performance monitoring technology available and the cost of procuring, installing, operating and maintaining such technology. This could include, but is not limited to, digital pilot light monitors, combustion temperature, gas flow meters, gas chromatography (GC) units, and passive remote monitoring of combustion efficiencies at the flare tip. Additional discussion of control devices, including flares, is included in section XIII.E of this preamble. 
      The EPA seeks comment on the cost, feasibility, emission reductions, and other benefits associated with options for reducing or eliminating venting and flaring of associated gas.  Among other things, we seek comment on how to require or incentivize operators to capture or beneficially use associated gas. We also seek input on the technical challenges, including but not limited to: needed infrastructure, land-use constraints, or other issues with capturing or beneficially using associated gas. And we seek comment on the technical challenges or constraints of reinjecting associated gas. 
      In order to evaluate BSER, the EPA seeks information on the capital costs and operation and maintenance expenses for options to capture, beneficially reuse, or reinject the associated gas. The EPA is aware of several pilot studies on beneficial reuse, and case studies that include the technical challenges and how they were overcome, limitations, costs involved, and payback periods would be informative. 
      In 2019, according to the EIA, the number of onshore gas producing oil wells in the U.S.  was 334,342 and the volume of vented and flared natural gas in 2019 was 523,936 million cubic feet. According to the 2021 GHGI, in 2019 venting of associated gas emitted 42,051 metric tons of CH - 4 and 1,291 metric tons of CO2 and flaring of associated gas emitted 81,797 metric tons of CH4 and 25,355,892 metric tons of CO2. Due to the significantly different emission profiles from venting versus flaring, the EPA seeks comment on how to differentiate those volumes, how to ascertain the number of existing oil production sites with flares already installed, and how many of those have flare performance monitoring capability in place.   
B. Abandoned Wells
      The EPA is soliciting comment for potential NSPS and EG to address issues with emissions from abandoned, or non-producing oil and natural gas wells that are not plugged or are plugged ineffectively. Should the EPA receive information through the public comment process that would help the Agency evaluate BSER, the EPA may propose NSPS and EG through a supplemental proposal. 
      The EPA broadly characterizes abandoned wells as oil or natural gas wells that have been taken out of production, which may include a wide range of non-producing wells. This includes wells with no recent production that are not plugged, which may be referred to as inactive, temporarily abandoned, shut-in, dormant, or idle. It also includes wells with no recent production and no responsible operator, which are commonly referred to as orphaned, deserted, or long-term idle. Finally, this includes wells that have been abandoned for long periods, known as legacy wells. State governments have varied definitions of temporarily idled, orphaned, or non-producing wells.
	It is the EPA's understanding that since non-producing oil and natural gas wells generally are not staffed and are seldom monitored, many have fallen into disrepair. The EPA recognizes that some states and NGOs also have elevated concerns about the potential number of low-production wells that could be abandoned in the near future as they reach the end of their productive lives. The 2021 GHGI estimates that in 2019 the U.S. population of abandoned wells (including orphaned wells and other non-producing wells) is around 3.4 million (about 2.7 million abandoned oil wells and 0.6 million abandoned natural gas wells). These non-producing wells often have methane, CO2, and VOC emissions. The most recent studies of emissions from abandoned wells focus on methane emissions, which are larger than the CO2 or VOC emissions from such wells. The GHGI estimates that abandoned oil wells emitted 209 kt of methane and 4 kt of CO2 in 2019. While emissions of both pollutants from abandoned oil wells decreased by 10 percent from 1990, the total population of these wells increased 28 percent. The GHGI estimates that abandoned gas wells emitted 55 kt of methane and 2 kt of CO2 in 2019. While emissions of both pollutants increased from abandoned gas wells by 38 percent from 1990, the total population of such wells increased 84 percent. 
      The large populations of abandoned unplugged wells are likely due to various circumstances. For instance, some operators declare bankruptcy before wells are plugged, and for many, bonding requirements represent only a fraction of the actual costs to plug the well and restore the well site. Wells are also abandoned or idled when changing oil or natural gas prices make them unprofitable to continue production. 
      The EPA recognizes that many oil and natural gas producing states require the plugging of non-producing oil and natural gas wells, and subsequent restoration of the well site. However, the large number of abandoned, unplugged wells nationwide suggests that Federal standards may be warranted. Many oil and gas producing states specify the time in which wells may remain in idle status without state approval. At the end of that time, states generally require tests of well integrity before giving approval for additional time in this idle status. 
      In its 2018 survey of idled and abandoned wells, the IOGCC documented state definitions and requirements for idled wells, as well as the management plans for those wells. There is variation in how states define these idle wells, ranging from no definitions to specific definitions for documented and undocumented orphaned and abandoned wells. Further, there is great variability in the allowance for the length of time a well may remain in idle status with or without approval, with some states limiting that time to a few months while other states allow idled status indefinitely. While some states require strict management plans of idled wells, others do not. Finally, some states provide funds for plugging, remediating, and reclaiming orphan wells, and others do not. These funds are supported by civil penalties, settlements, forfeited bonds, and state appropriations. The IOGCC's survey found that 28 states and Canadian provinces have wells approved to remain in idle status, with most having between 100 and 10,000 approved idle wells. Most states and provinces maintain inventories of documented orphan wells and prioritize orphan wells for plugging according to risk. States and provinces reported from zero to 13,266 documented orphan wells, with about half reporting fewer than 100 orphan wells. 
      The IOGCC's 2018 survey also collected estimates from some states on the number of undocumented orphan wells, including those for which no permits or other records exist. Most of these wells were drilled before there was any regulatory oversight. Ten states reported no undocumented orphan wells. Nine other states did not provide an estimate. Eleven states provided an estimate ranging from fewer than 10 to 100,000 or more undocumented orphan wells. Most of the states surveyed by the IOGCC had established funds dedicated to plugging orphan wells. Money for these funds comes primarily from taxes, fees, or other assessments on the oil and gas industry.
      The EPA has identified the following potential strategies to reduce air emissions from these sources. The first strategy is to employ practices and procedures to ensure proper well closure. Under this strategy, the EPA could focus on well closure requirements aimed at preventing future abandonment of unplugged wells and halt the growth of this unplugged population. Given that all wells eventually reach their end of life, this strategy could be applied to both new and existing wells. Under the NSPS, for example, the EPA could require owners or operators to submit a closure plan describing when and how the well would be closed and how much bond money has been paid or set aside for plugging, or we could define a threshold for the amount of bond money or other financial assurance mechanism to be set aside that represents an approximation of the cost of plugging wells; and require reporting any transfer of well ownership, along with a copy of the well closure requirements, to the EPA and/or the applicable state when transferring ownership. 
      A second strategy is to require financial assurance for well closure. As described previously, several states have taken steps to require financial assurance when addressing the closure of orphaned and abandoned wells. The primary purpose of financial assurance, often called bonding, is to ensure that state governments have adequate resources to plug oil and gas wells when the owner or operator is unwilling or unable to do so. The IOGCC notes that states typically have requirements for both single-well or blanket financial assurance. In the IOGCC's 2018 survey, 35 states reported information on the types of financial assurance accepted in their jurisdictions, with most accepting more than one type. The IOGCC noted that the amounts and criteria for bonding vary considerably among the states. Single-well bond amounts range from $1,500 to $500,000 per well; blanket bonds (covering multiple wells) vary from $7,500 to $30,000,000, the IOGCC said. In some states, bond amounts are based on well depth; in others, bond amounts are based on case-by-case evaluations; and in several, bond amounts may be increased if determined necessary.
      That study identified the following types of financial assurance, including cash deposit of a payment given as a guarantee that an obligation will be met, certificate of deposit of a financial instrument certifying that the face amount is on deposit with the issuing bank to be redeemed for cash by the state if required, financial statements of a report of basic accounting data that depicts a firm's financial history and activities, letter of credit, irrevocable letter of credit where payment is guaranteed if stipulated conditions are met, security interest giving the right to take property or a portion of property offered as security, and surety or performance bonds as a contract by which one party agrees to make payment on the default or debt of another party. Other forms of financial assurance include certificates of insurance, consolidated financial funds, escrow accounts, and liens. The amounts and criteria for financial assurance vary considerably among the states and provinces.
      The third strategy under consideration is to require fugitive emissions monitoring at a specified frequency for the duration of time the well is idled and unplugged. The EPA's understanding, however, is that most idled and non-producing well sites would be classified as wellhead only sites, which the EPA is proposing to exclude from fugitive emissions monitoring for both new and existing well sites (see section XI.A). 
      The EPA is soliciting additional information that would support a determination of the BSER to address emissions from abandoned, idled, and non-producing wells. The specific information of interest includes updates to the number of abandoned, orphaned, or temporarily idled wells in the U.S., which could be state-specific or basin-specific; fugitive emission estimates for the wells; and costs of mitigation measures, including effective closure requirements and proper plugging practices, financial assurance mechanisms, and requiring fugitive emissions monitoring while in idled and unplugged status. The EPA is also soliciting information on mechanisms to disincentivize operator delay in permanently abandoning wells and/or transfer of late-life assets to companies that may not be well-positioned to fund proper closure. The EPA also solicits information at the state level, on the length of time that wells remain temporarily idled before they must be inspected by state governments. Further, we are seeking information about what would be included in well closure requirements, including what closure requirements are appropriate and any recordkeeping and reporting associated with those requirements. The EPA solicits comment on effective plugging, such as criteria or guidelines are necessary for sufficient plugging and post-plugging follow up monitoring necessary over a certain time period. Finally, the EPA solicits comments on the cost of monitoring idled or abandoned wells, or monitoring techniques that might lower the costs of such monitoring.
C. Pigging Operations and Related Blowdown Activities

      The EPA is soliciting comment for potential NSPS and EG under consideration that include addressing emissions from pipeline pigging and related blowdown activities. Should the EPA receive information through the public comment process that would help the Agency evaluate BSER, the EPA may propose NSPS and EG through a supplemental proposal. 
      Raw natural gas is transported from production wells to natural gas processing plants through networks of gathering pipelines. After natural gas processing, pipeline networks in the transmission and storage segment transport the gas to downstream customers. Raw natural gas is frequently saturated with hydrocarbons and may contain other components such as water, carbon dioxide, and hydrogen sulfide, especially upstream of the natural gas processing plant. Liquid condensates can accumulate in low elevation segments of the gathering pipelines, impeding the flow of natural gas. To maintain gas flow and operational integrity of the gathering pipelines, operators mechanically push these condensates out of the low elevations and down the pipeline by an operation called "pigging," which involves first inserting a device called a piginto a pig launcher upstream of the pipeline segment where condensates have accumulated. The natural gas flowing through the pipeline then pushes the pig through the pipeline, allowing the pig to sweep along the accumulated condensates. The pig is removed from the pipeline segment when it is caught in a pig receiver. Pigging operations are also conducted using "smart" pigs that are equipped with sensors to collect data about the pipeline's structural characteristics and integrity for safety and maintenance purposes.
      Before a pig can be inserted or removed through the hatch of a pig launcher or a pig receiver, the pipeline gas in the launcher or receiver barrel must be removed. It is common practice to vent the gas directly to the atmosphere where gas capture or control are not used. This gas is under the same pressure as the pipeline and contains methane, ethane, and VOCs including HAP such as benzene, toluene, ethylbenzene, and xylene. Emissions can also result from the volatilization of collected condensate liquid when the pig barrel is depressurized. 
      Pig launchers and receivers can exist in conjunction with other operations, such as at a compressor station or natural gas processing plant, or can be "stand-alone" sites, where the only equipment at a particular location is related to pigging operations. Additionally, sections of pipeline or equipment that are separate from the pig launcher or receiver may need to be evacuated of gas for reasons other than pigging, such as routine maintenance or inspection activities. Emissions from blowdowns can be calculated by accounting for the volume of the section of pipeline or equipment being evacuated, composition of that gas being vented, pressure of the gas vented, frequency of the blowdown activity, and inclusion of emissions from any volatile liquids present in the pipeline section or equipment being vented. 
      The EPA is aware of some state and local governments have regulations in place that address blowdown activities, including pigging. These include limits on the amount of emissions from pigging operations, required use of add-on controls, and implementation of best management practices. Estimating emissions from pigging operations is fairly straightforward if all variables (e.g., volume, pressure, and composition of gas) are known. However, the wide range of variables, which are applied in different combinations and are dependent on the frequency of blowdown events, can make it challenging to estimate total nationwide emissions from pigging and related blowdown activities. For example, in 2019, six of the eight operators reporting to GHGRP subpart W in the Uinta Basin reported a collective 7,299 blowdown events due to pigging that met the threshold for reporting under GHGRP subpart W, but the attribution of emissions from each individual pigging event is undetermined at this time. Data reported in 2019 under GHGRP subpart W include 472,995 total individual blowdown events from 1,212 facilities for a combined 307,630 metric tons of methane emitted, including 79,746 events at pig launchers or receivers for a combined total of 19,066 metric tons of methane, however, these data only include emissions from blowdown equipment with a unique physical volume greater than 50 cubic feet and occurring at a facility with total emissions greater than 25,000 metric tons CO2 Eq. The EPA is also aware of a single operator in the Marcellus Shale region that operates around 400 pig launchers and receivers which collectively emit approximately 1,472 short tons of methane annually, but the total annual emissions from each launcher or receiver varies widely, due to variations in the inputs used to calculate emissions from an individual pigging event.The EPA is seeking comment on the availability of nationwide data sets or methodologies to better identify the total inventory of pig launchers and receivers, and, if no such data set or proxy exists, comment on the most defensible method of calculating total emissions from pigging and related blowdown activities. 
      The EPA has identified the following potential control options that can reduce emissions from pipeline pig launchers and receivers: (1) reducing the frequency that the pig launcher or receiver must be evacuated of gas; (2) eliminating or reducing the volume of gas vented during blowdowns; (3) using add-on controls that are applied to blowdown emissions; or (4) a combination of these strategies. The EPA has identified the following systems as potential control strategies to evaluate further. 
      First, pig ball valves are a design alternative to conventional pig launcher and receiver systems that have a smaller sized barrel (or chamber) that launches and receives the pig, thus resulting in reduced emissions from pigging operations. A conventional pig launcher or receiver system can be retrofitted by replacing the conventional launcher and receiver barrels with special ball valves used to insert and remove the pig directly from the main pipeline. By replacing the large volume barrel with the much smaller volume ball valve, the volume of gas vented during each pigging operation can be reduced by as much as 80 to 95 percent, with a corresponding reduction in emissions and other risks associated with pipeline pigging operations. The net cost of a pig ball valve compared to a traditional launcher/receiver should consider not only the cost of the valve and its installation, but also the savings realized from the prevention of large quantities of vented gas and personnel time spent blowing down a larger launcher/receiver. These costs and savings will vary according to site-specific dimensions, gas composition, and pigging frequency. The EPA understands that not every dimension of pipeline and pig launcher or receiver can use a pig ball valve and seeks further comment on specific circumstances where such equipment is appropriate, potential challenges to using a pig ball valve or retrofitting a launcher or receiver to accommodate a pig ball valve, and specific costs of installing or retrofitting a launcher or receiver compared to a conventional full-barrel launcher or receiver.
      Second, multi-pig launcher systems are a design alternative to conventional launcher/receiver systems and reduce pigging emissions by reducing the frequency that launchers and receivers must be opened to the atmosphere and vented prior to pig insertion and removal. The launcher barrel is designed to hold multiple spherical pigs, which are each held in place by gates or pins prior to release. Emission reductions are approximately proportional to the reduction in frequency of opening the launcher and receiver hatch. For example, if a pig launcher holds six pigs, which are loaded all at once, the frequency of venting of the pig barrel is reduced to one-sixth of what it would have been if each pig were loaded individually. The EPA understands that multi-pig launchers and receivers are most appropriate for large diameter pipelines where the footprint of the launcher or receiver site is large enough to accommodate such a system. The EPA seeks comment on specific circumstances where such equipment is appropriate, and requests information on emission reductions and specific costs and savings of installing or retrofitting and operating a multi-pig launcher or receiver compared to a conventional single-pig launcher or receiver.
      Next, there are several liquids management technologies that focus on reducing emissions from the liquid condensate that is collected during pigging operations. The first technology relates to the design of condensate drains on receiver barrels. Drains can be installed in the bottom of receiver barrels and pig ball valves to ensure that all condensate is drained from the system prior to depressurization. These drains generally route the condensate back into the main pipelines, to onsite storage tanks, or to onsite processes via enclosed piping and can be retrofitted to existing systems. Recovering condensate prevents emissions that would occur when the liquids volatilize during depressurization of the pig receiver. The EPA seeks comment on different configurations of condensate drains, how the recovered condensate is routed and managed, limitations on using this technology, and data showing the amount of condensate recovered and associated emissions prevented.
      The second liquids management technology is a pig ramp on a receiver barrel. A pig rampis a simple device that can be installed inside a receiver barrel to allow liquids trapped in front of the pig to be captured and to allow liquids clinging to the pig itself to drain before the pig is pulled from the chamber. Pig ramps are typically used in conjunction with condensate drains. The pig ramp promotes the flow of liquid through the barrel and into the drain line by elevating the pig on a rack-like apparatus within the receiver barrel, thereby preventing the pig from creating blockages in the receiver. By promoting the flow of liquid to a location within the receiver or pipeline where the liquids can be captured and drained prior to depressurization, pig ramps reduce the amount of condensed VOCs that would otherwise volatilize during depressurization and removal of the pig from the receiver, thereby reducing emissions. The EPA seeks comment on the successful installation and use of pig ramps as well as information on cost, emission reductions, and concerns or challenges that may make the use of pig ramps inappropriate. 
      The third liquids management technology involves enhanced liquids containment. If recovered condensate cannot be routed back to the pipeline or to controlled storage vessels, covering containers that collect liquids remaining in a receiver barrel after depressurization with a fitted impermeable material will reduce emissions from evaporation. However, whether or not this strategy will ultimately reduce emissions depends on how the recovered condensate is actually managed. The EPA seeks comment on how recovered condensate can be managed to ensure that emissions from the volatilization of the liquids is minimized, thereby achieving emissions reductions. 
	Lastly, the EPA has identified several additional control options that can be employed to reduce emissions. First, an owner or operator could install "jumper lines" that allow routing high pressure systems to lower pressure systems. The depressurization emissions from high pressure launchers and receivers can be reduced by routing the high-pressure gases to a lower pressure system before venting the remaining gases to the atmosphere or to control equipment. Routing to a lower pressure system is achieved with a depressurization line (or jumper line) exiting the top of the barrel, or exiting the top of the pig ball valve, and connecting to nearby low-pressure lines on site. Compressor stations and gas plants have low pressure lines on the site that typically can receive these depressurized gases and recycle them through the process. Similarly, launchers and receivers along high pressure pipelines are occasionally located near low pressure pipelines that can receive depressurized gases exiting the barrel or pig ball valve. The EPA seeks comment on the universe of sites where jumper lines are feasible to install, as well as information on cost, emission reductions, and comment on implementation successes and challenges.
      Second, owners and operators can route low-pressure systems into a fuel gas system or VRU. Gases that remain in high pressure barrels after venting to low pressure systems, and gases in low pressure barrels, can be recovered during depressurization by discharging the gases to very low-pressure systems at the site (e.g., 10-15 psig). Two examples of very low-pressure systems at compressor stations are a fuel gas system and a condensate tank VRU. Applying such an approach can reduce the gas pressure in the barrels to the pressure of the very low-pressure system, with a corresponding reduction in depressurization emissions. The feasibility of this option is contingent upon the presence of such equipment already onsite. The EPA seeks comment on the universe of sites where routing gas to low-pressure systems is feasible, as well as information on cost, emission reductions, and comment on implementation successes and challenges.
	Third, owners and operators can utilize barrel pump-down systems. In barrel pump-down systems, small fixed or portable compressors are used to pump vapors in the receiver or a launcher barrel back into the main pipeline prior to venting and opening the barrel hatch. In barrel pump-down systems, the inlet of a gas compressor is connected to the receiver or launcher depressurization line, and the compressor discharge is connected into the main pipeline. Vapors exiting the depressurization line are pulled into the compression system and recovered back into the pipeline at system pressure. These control systems can recover greater than 99 percent of the depressurization vapors from pig launchers and receivers. The EPA seeks comment on the universe of sites where barrel pump-down systems are feasible, as well as information on cost, emission reductions, and comment on implementation successes and challenges.
	Finally, owners and operators could route depressurization gases to combustion devices to control emissions from pigging operations. Depressurization gases from barrels and pig ball valves can be routed through the depressurization line to onsite combustion devices. Well-designed and operated combustion devices can achieve vapor destruction efficiencies as high as 95 to 98 percent. Combustion devices can be used in conjunction with engineering solutions discussed above that first reduce accumulation of or recover as much natural gas and condensate as possible, before destroying the remaining vapors in the combustion device. An example would be to route high pressure systems to low pressure lines and drain barrel condensate, then route the remaining vapors to a combustion device. The EPA understands that large, high-capacity combustion devices are typically available at compressor stations and processing plants and can be used to control pigging gases while meeting the other flaring needs of the facility. There are also numerous low-capacity combustion devices available for serving remote launcher/receiver sites. The EPA seeks comment on the universe of sites where routing depressurization gases from pigging operations to a combustion device is feasible, as well as information on cost, emission reductions, and comment on implementation successes and challenges.
      In addition to those methods already identified above for reducing emissions from pigging and related blowdown activities, the EPA is seeking comment on other existing technologies and work practices to reduce the need for blowdown events or reduce emissions from blowdown events when they occur. The EPA is specifically interested in the costs of such technologies or work practices and any variables impacting cost, the control efficiency of the technology or work practice and variables affecting efficiency, and any technological or logistical limitations to implementing the technology or work practice.
      While blowdown emissions due to pigging are the primary area where the EPA seeks comment, the EPA is aware that planned blowdowns occur for many reasons, typically related to maintenance or inspection activities. Planned blowdowns may occur at facilities such as a gas processing plant, compressor station, well pad, or stand-alone pig launcher and receiver station, but may also occur at locations other than these facilities, including along pipelines. Under GHGRP subpart W, blowdown vent stack equipment or event types are grouped into the following seven categories: facility piping (i.e., piping within the facility boundary other than physical volumes associated with distribution pipelines), pipeline venting (i.e., physical volumes associated with distribution pipelines vented within the facility boundary), compressors, scrubbers/strainers, pig launchers and receivers, emergency shutdowns (this category includes emergency shutdown blowdown emissions regardless of equipment type), and all other equipment with a physical volume greater than or equal to 50 cubic feet. The EPA seeks comment on any substantive differences between pigging blowdowns and other types of planned blowdowns. Further, the EPA is soliciting comment on how to define an affected facility that includes these blowdown activities, and specific limitations (e.g., technical or logistical) to including non-pigging-related types of blowdowns as part of affected facilities. In particular, the EPA is considering whether the pipeline itself could be defined as an affected facility for purposes of regulating blowdowns. In this scenario, the owner or operator of the pipeline would be responsible for complying with any requirements in place for blowdown activities that occur anywhere along the pipeline. The EPA is soliciting comment on any potential concerns this type of approach would raise for owners and operators, particularly where pipelines cross state boundaries or at the location where pipeline ownership may change from the upstream owner to a different downstream owner. 
D. Tank Truck Loading
      The EPA is considering including emission standards and EG for tank truck loading operations; however, additional information is needed to evaluate BSER and propose NSPS or EG for this emissions source. The EPA is therefore soliciting comment on adding tank truck loading operations as an affected facility in both the NSPS and EG. Depending on the information received through the public comment process, the EPA may propose NSPS and EG for this source through a supplemental proposal. In this section we summarize the available information we have reviewed for this emissions source and potential control options. 
      Tank truck loading operations result in emissions when organic vapors in empty tank trucks are displaced to the atmosphere as crude oil, condensate, intermediate hydrocarbon liquids, or produced water from storage vessels is loaded into the tank trucks. Tank truck loading emissions are the primary source of evaporative emissions from tank trucks. It is the EPA's understanding that these vapors are a composite of vapors formed in the empty tank by evaporation of residual materials from previous loads, vapors transferred to the tank in vapor balance systems as materials are being unloaded, and vapors generated in the tank as new material is being loaded. Further, the quantity of evaporative losses from loading operations is, therefore, a function of the parameters such as the physical and chemical characteristics of the crude oil, condensate, intermediate hydrocarbon liquids, or produced water; the method of unloading the crude oil, condensate, intermediate hydrocarbon liquids, or produced water from the storage vessel into the tank truck; and the operations to transport the empty tank truck off-site. The composition of evaporative losses includes VOC, methane, and some HAP. 
      According to the 2017 NEI, VOC emissions from tank loading operations were approximately 72,448 tpy, of which over 70,990 tpy were emitted in the crude oil and natural gas production segment, with the balance of approximately 1,457 tpy emitted from the natural gas processing segment. According to the Oklahoma loading losses guidance,  a loading loss vapor VOC content of 85 percent by weight (i.e., 15 percent by weight methane and ethane) may be assumed at wellhead facilities. Condensate and crude oil being loaded at a facility other than a wellhead facility may assume a vapor VOC content of 100 percent. Applying these compositions to the emissions in the 2017 NEI results in approximately 12,528 tpy methane at well sites and 1,457 tpy methane from other segments. 
      According to EIA, the contiguous continental states area comprising of 48 states have a five year daily average condensate production of 911,000 bbls/day. Emissions per barrel of liquids loaded into tank trucks may be estimated at 0.43lb VOC/bbl. It is the EPA's understanding that most sites use tank trucks with a capacity of approximately 130 bbl.
      The EPA understands that there are three options generally in use for controlling emissions during the tank truck loading process. The first control option is vapor balancing which is used to route the vapors displaced during material loading from the tank truck back to the storage vessel. Vapor balancing requires a vapor capture line to connect the tank truck to the storage vessel or manifold system of a tank battery. Because vapor balancing is a closed system, the only anticipated emissions from this control option would be fugitive in nature. However, emissions may occur from the tank truck if it is not properly maintained to DOT specifications, or when the tank is cleaned or reloaded without control off-site. Vapor balancing does not have any secondary air impacts or energy requirements. We estimate the capital cost associated with a vapor balancing loading arm (equipment associated with a capture line to connect the tank truck to the storage vessel) at about $5000 per arm based on limited available information.       
      The second control option is use of a closed vent system operating with a reduction efficiency of 95 to 99 percent. A vapor capture system is used and routed to a vapor recovery device (VRD) or VRU which uses refrigeration, absorption, adsorption, and/or compression. The recovered product is piped back to storage. Alternatively, the vapors may be collected via a vapor capture system and routed to an on-site thermal oxidizer or flare. It is possible to route emissions from this closed vent system to an existing control device located on-site for another purpose. The EPA recognizes that this option may have secondary impacts dependent on the type of control chosen (e.g., VRU, VRD, or combustion device). 
      Finally, the third option is to directly pipe liquids downstream. By directly piping liquids downstream, no emissions from tank truck loading are released to the atmosphere. We are not aware of any secondary impacts or energy costs associated with this option. However, the EPA is also unsure if this option is technically feasible for every site. It is our understanding that this option requires access to pipelines that can transport the crude oil and/or condensate to downstream locations, and availability of pipelines or capacity to move these liquids in existing pipelines may present an issue with requiring this option for all sites.
      In addition to these three control options, the EPA has also identified work practices related to the method of loading which are important and play a role in minimizing air emissions. Practices such as submerged fill and bottom loading help reduce emissions when the fill pipe opening is below the liquid surface level which reduces liquid turbulence and results in much lower vapor generation than encountered during splash (top) loading. We estimate the capital costs of submerged fill loading arms are approximately $1,500 per arm based on limited available data at this time.
      The EPA is soliciting comment on the three control options and work practices presented in this section to control or reduce emissions resulting from the tank truck loading process. We solicit comment on other control options or other work practice standards similar to those used in other sectors such as petroleum refineries and how appropriate those options may be for the Crude Oil and Natural Gas source category. We solicit comment on how widely used the control measure and work practices are, any feasibility challenges, and estimates of baseline emissions and cost information associated with these control options and work practices. The EPA is aware of several state regulations that have established standards for this emissions source. Finally, the EPA solicits comment on any practices owners and operators already implement as part of voluntary efforts or state requirements to minimize emissions from these sources. 
E. Control Device Efficiency and Operation 
      As discussed above in sections XI.B, F, and G and XII.B, F, and G, the EPA is proposing to retain the 95 percent reduction performance standard for storage vessels, wet seal centrifugal compressors, and pneumatic pumps based on our analysis showing that a combustion control device remains the BSER for these affected facilities and can reliably achieve this performance standard. This 95 percent reduction is generally achieved by capturing the emissions in a closed vent system that routes those emission to either a control device or back to the process. Under the 2016 NSPS OOOOa, as amended by the 2020 Technical Rule with further amendments proposed in this action, closed vent systems must be designed and operated with no detectable emissions, which is defined as either no emissions detected greater than 500 ppm above background with EPA Method 21, no emissions detected with OGI, or no audible, visual, or olfactory emissions detected. Thus, for a closed vent system, the assumed control efficiency is 100 percent. Therefore, any control device used must be designed and operated to achieve at least 95 percent reduction of emissions to comply with the standard. Examples of control devices include flares, thermal oxidizers, catalytic oxidizers, enclosed combustion devices, carbon adsorption systems, condensers, and VRUs. However, there are various data sources available that suggest combustion control devices, which we have again identified as the BSER for these affected facilities, can achieve a continuous destruction efficiency of 98 percent.
      Therefore, the EPA is soliciting comment on potentially proposing a change in the standards for wet seal centrifugal compressors, storage vessels, and pneumatic pumps that would require 98 percent reduction of methane and VOC emissions from these affected facilities. It is the EPA's understanding that combustion control devices, such as flares and enclosed combustion devices, may achieve at least 98 percent control of all organic compounds. Further, as noted in AP-42 Chapter 13.5, properly operated flares achieve at least 98 percent destruction efficiency in the flare plume in normal operating conditions. However, the EPA has received some data relevant to the use of these controls at oil and gas facilities that indicates air-assisted and steam-assisted flares have been found operating outside of the conditions necessary to achieve at least 98 percent control efficiency on a continuous basis. Therefore, the EPA is soliciting comment and information that would help us better understand the cost, feasibility, and emission reduction benefits associated with establishing a 98 percent control efficiency requirement for flares in the Crude Oil and Natural Gas source category, including information on the level of performance being achieved in practice by flares in the field, what conditions or factors contribute to malfunctions or poor performance at these flares, and what measures the EPA could or should require in order to ensure that flares perform at a 98 percent level of control. The EPA also requests comment on whether additional measures to ensure proper performance of flares would be appropriate to ensure that flares meet the current 95 percent control requirement. For example, the EPA is soliciting comment on the specific requirements that could be used to demonstrate continuous compliance when using a combustion control device. In its July 8, 2021, report, the Office of Inspector General (OIG) observed that state permitting authorities had difficulty verifying continuous compliance with combustion efficiency requirements for flares and enclosed combustors. The OIG recommended that the EPA explore additional means to verify continuous compliance in NSPS OOOO and NSPS OOOOa that would provide additional tools for state agencies to properly permit and enforce combustion efficiency. In considering this recommendation, the EPA has determined that additional information is necessary to support the development of cost-effective continuous compliance requirements. 
      The current standards in NSPS OOOO and NSPS OOOOa require owners and operators to perform an initial demonstration of compliance for all control devices used to meet the standards in the rule. Further, NSPS OOOO and NSPS OOOOa require monthly EPA Method 22 observations to demonstrate continuous compliance with visible emission requirements, in addition to monitoring for the presence of a pilot light. When an enclosed combustion device is used, owners and operators may demonstrate initial compliance through field testing or through manufacturer testing. The EPA maintains a list of devices for which manufacturers have demonstrated compliance with the testing requirements, including achieving a destruction efficiency of at least 95 percent. The devices that have demonstrated compliance through manufacturer testing have achieved greater than 98 percent destruction efficiency; however, this is demonstrated in a testing environment only, and while the testing is designed to challenge the units, the units may not necessarily demonstrate the same destruction efficiency in field applications. The EPA is seeking comment on alternative means to demonstrate continuous compliance with the required control efficiency (whether maintained at 95 percent or increased to 98 percent). 
      The Petroleum Refinery Sector Standards, 40 CFR part 63, subpart CC, were amended in 2015 (80 FR 75178) to include a series of additional monitoring requirements that ensure flares achieve the required 98 percent control of organic compounds. Previously these flares had been subject to the flare requirements at 40 CFR 60.18 in the part 60 General Provisions. More recently, the updated flare requirements in NESHAP subpart CC have been applied to other source categories in the petrochemical industry, such as ethylene production facilities (40 CFR part 63, subpart YY), to ensure that flares in that source category also achieve the required 98 percent control of organic compounds. These monitoring requirements include continuous monitoring of waste gas flow, composition and/or net heating value of the vent gases being combusted in the flare, assist gas flow, and supplemental gas flow. The data from these monitored parameters are used to ensure the net heat value in the combustion zone is sufficient to achieve good combustion. The monitoring also includes prescriptive requirements for monitoring pilot flames, visible emissions, and maximum permitted velocity. Lastly, where fairly uniform, consistent waste gas compositions are sent to a flare, owners or operators can simplify the monitoring by taking grab samples in lieu of continuously monitoring waste gas composition, and in some instances, engineering calculations can be used to determine flow measurements.
      While effective, the EPA seeks comment on how appropriate any such monitoring requirements and systems would be for the oil and gas production, gathering and boosting, gas processing, or transmission and storage segments subject to the proposed NSPS OOOOb and EG OOOOc. The EPA seeks comment on how to distinguish among flare units where such monitoring is practical, and alternatives where such systems are not practical because they lack continuous, on-site personnel or do not have the supporting infrastructure.
      Additionally, the EPA seeks comment on several facets of ongoing compliance, including: (1) owner or operator experience in determining the proper location of a thermocouple for monitoring the presence of a pilot flame, and how to avoid pilot flame failure; (2) how OGI may be used to identify poor combustion efficiency (e.g., to effectively utilize OGI to qualitatively screen enclosed combustion devices) for additional quantitative testing. For instance, the EPA is interested in how OGI has been used to evaluate heat signature of gases exiting the top of the stack and/or the presence of any unburned hydrocarbon trailing or advective plumes. 
      With respect to enclosed combustors, the EPA is seeking information on the development of comprehensive specifications for creating an operating envelope under which a make/model can achieve 98 percent reduction (i.e., parameters that should be identified on enclosed combustion device specification sheets), such as maximum heat load, minimum heat load, minimum inlet pressure of waste gas stream, temperature of combustion zone (and proper location for temperature monitor), air intake rate, operation and maintenance necessary for optimal combustion. The EPA also seeks information on real-time monitoring of enclosed combustion device inlet waste gas stream pressure aimed at achieving higher combustion efficiency.  
      The EPA is also soliciting comment on the current use of non-combustion control devices, the practicality of requiring 98 percent reduction through the use of non-combustion control devices, and the monitoring requirements necessary to demonstrate initial and continuous compliance with such control efficiency. NSPS OOOO and NSPS OOOOa require parametric monitoring for condensers, carbon adsorption systems, and similar control devices, to demonstrate continuous compliance. However, the EPA is seeking comment on whether those monitoring requirements are sufficient to assure continuous compliance should the EPA propose a requirement of 98 percent reduction. In addition to monitoring requirements, the EPA is seeking information on what additional records should be maintained and/or reported for demonstrating continuous compliance when non-combustion control devices are used. The EPA is particularly concerned that increasing the level of control from 95 to 98 percent would disincentivize use or potentially force replacement of non-combustion control devices entirely, including those that capture product for reuse in vapor recovery systems. For example, Texas requires additional monitoring and other significant engineering upgrades for a VRU operator to meet a higher control efficiency than 95 percent. Adding to this concern is the potential increase in overall costs of the rule and potential increase in emissions where facilities replace non-combustion control devices with combustion control devices.
      Finally, the EPA is seeking comment on new technologies that would address control efficiency from flares specifically and provide real-time or near real-time measurement of control efficiency. One example would be OGI continuous flame imaging systems that capture flame size and temperature to ensure these parameters are within acceptable ranges. New optical technology is in the early phases of development and deployment. The EPA acknowledges that it may be challenging to analyze costs and reductions without comprehensive data specific to a particular technology, but in the interest of a forward-looking standard, we seek information on potential methods to assure continuous compliance for these control devices. 
F. Definition of Hydraulic Fracturing 
During pre-proposal outreach, a number of small businesses stated that the NSPS has unintentionally been applied to conventional and vertical wells that engage in hydraulic fracturing. The small business stakeholders contended that these wells have a very different profile from unconventional or horizontal wells in terms of footprint, water usage, chemical usage, equipment used, and flowback period. They recommend that the EPA explicitly exempt these wells from the proposal. We maintain that the original intent of the NSPS was to regulate hydraulicly fractured wells, in both conventional and unconventional reservoirs, and both vertical and horizontal wells.
NSPS OOOOa defines hydraulic fracturing as "the process of directing pressurized fluids containing any combination of water, proppant, and any added chemicals to penetrate tight formations, such as shale or coal formations, that subsequently require high rate, extended flowback to expel fracture fluids and solids during completions." The NSPS does not offer numeric thresholds that define "tight formations" or "high rate, extended flowback". When developing the original NSPS OOOO, EPA's analysis assumed hydraulic fracturing is performed in tight sand, shale, and coalbed methane formations which have an in situ permeability (flow rate capability) to gas of less than 0.1 millidarcy. The EPA also assumed the flowback lasted between 3 and 10 days for the average gas well, and 3 days for the average oil well. However, in response to a public comment on the 2015 NSPS OOOOa proposal claiming the definition of hydraulic fracturing was too broad, the EPA clarified it intended to "include operations that would increase the flow of hydrocarbons to the wellhead". Similarly, in response to a public comment seeking an exemption for wells that have a flowback period of less than 24 hours, the EPA acknowledged that there is a range of flowback periods, finding that the requested exemption was not warranted.    
We are soliciting comment on if numeric thresholds for "tight formations" or "high rate, extended flowback" are appropriate to include in the definition of hydraulic fracturing, and if so, what those numeric thresholds should be. Alternatively, we solicit comment on if it is appropriate to align the NSPS definition with the U.S. Geologic Survey (USGS) definition of hydraulic fracturing ("the process of injecting water, sand, and/or chemicals into a well to break up underground bedrock to free up oil or gas reserves"), which may more accurately capture the EPA's original intent.    
XIV. State, Tribal, and Federal Plan Development for Existing Sources
      Over the last forty years, under CAA section 111(d), the agency has regulated four pollutants from five source categories (i.e., sulfuric acid plants (acid mist), phosphate fertilizer plants (fluorides), primary aluminum plants (fluorides), kraft pulp plants (total reduced sulfur), and municipal solid waste landfills (landfill gases)). In addition, the agency has regulated additional pollutants under CAA section 111(d) in conjunction with CAA section 129. The Agency has not previously addressed emissions of GHGs (in the form of limitations of methane) from the Crude Oil and Natural Gas source category under CAA section 111(d). However, the EPA has ample experience with this source category from implementing the NSPS for so long, and has examined existing sources in a variety of context including the 2013 Federal Implementation Plan (FIP) for oil and natural gas well production facilities on the Fort Berthold Indian Reservation (78 FR 17836 (Mar. 22, 2013)), the 2016 Oil and Natural Gas Control Techniques Guidelines (81 FR 74798 (Oct. 27, 2016)), and the 2020 proposed FIP for managing emissions from oil and natural gas sources on Indian country lands within the Uintah and Ouray Indian Reservation (85 FR 3492 (Jan. 21, 2020)). The draft EG contained in this proposal draw from, among other sources of information and analysis, all of these experiences combined with information on state laws that regulate existing sources. In this action, the EPA is proposing EG for states to follow in developing their plans to reduce emissions of GHGs (in the form of limitations on methane) from designated facilities within the Crude Oil and Natural Gas source category.   
A. Overview 
      While section IV above provides a general overview of the state planning process triggered by the EPA's finalization of EG under CAA section 111(d), this section explains the EG process and proposed state plan requirements in more detail, and also solicits comment on various issues related to this EG. The EG process is governed by CAA section 111(d) as well as the final EG and the EPA's implementing regulations at 40 CFR Part 60 Subpart Ba. After the EPA establishes the BSER in the final EG, as described in preamble sections XI and XII, each state that includes a designated facility must develop, adopt, and submit to the EPA its state plan under CAA section 111(d). The EPA then must determine whether to approve or disapprove the plan. If a state does not submit a plan, or if the EPA does not approve a state's plan, then the EPA must establish a Federal plan for the state. 
      Each of these steps, and more, is discussed in detail in this section which is organized into six parts. First, we discuss the components of the EG. Second, we discuss establishing standards of performance in state plans in response to a finalized EG. Third, we discuss the components of an approvable state plan submission. Fourth, we discuss the timing for state plan submissions and compliance times. Fifth, we discuss the EPA's action on state plans and promulgation of a Federal plan, if needed. Sixth, we discuss the CAA section 111(d) process as it relates to tribes. While this section describes the requirements of the implementing regulations under 40 CFR 60 subpart Ba, proposes requirements for states in the context of this EG, and solicits comments in the context of this EG, nothing in this proposal is intended to reopen the implementing regulations themselves for comment.
B.  Components of EG
	As previously described, CAA sections 111(d)(1) and 111(a)(1) collectively establish and define certain roles and responsibilities for the EPA and the states. The EPA addresses its responsibilities by drafting and publishing EG in accordance with 40 CFR 60.22a, which "[contain] information pertinent to control of the designated pollutant from designated facilities." Mirroring language included in CAA section 111(d)(1), the EPA's implementing regulations define a designated pollutant as "any air pollutant, the emissions of which are subject to a standard of performance for new stationary sources, but for which air quality criteria have not been issued and that is not included on a list published under section 108(a) or section 112(b)(1)(A) of the Act." 40 CFR 60.21a(a). The EPA's implementing regulations also define a designated facility as "any existing facility (see § 60.2) 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 section 60.2)." Id. at 60.21a(b). The designated pollutant for purposes of the draft EG included in this proposal is GHGs, but the presumptive standards in the EG are expressed in terms of limitations on methane. A description of each of the designated facilities included in the draft EG can be found above in preamble sections XI and XII.
	More specifically, 40 CFR 60.22a(b) lists six components to be included in EG to provide information for development of the state plans triggered by the promulgation of the EG. First, EG must include information regarding the "endangerment of public health or welfare caused, or contributed to, by the designated pollutant." 40 CFR 60.22a(b)(1). Information on the harmful public health and welfare impacts of methane emissions from the oil and natural gas industry are included above in section III of this document. Second, the EG must include a "description of systems of emission reduction which, in the judgment of the Administrator, have been adequately demonstrated." 40 CFR 60.22a(b)(2). The EPA has included such a description above in sections XI and XII of this preamble and the TSD located at Docket ID No. EPA-HQ-OAR-2021-0317. Third, the EG must include information regarding "the degree of emission limitation" achievable through application of each system, along with information "on the costs, non-air quality health environmental effects, and energy requirements of applying each system to designated facilities." 40 CFR 60.22a(b)(3). The EPA has included such a description in sections XI and XII of this preamble and the TSD located at Docket ID No. EPA-HQ-OAR-2021-0317. Fourth, the EG must include information regarding the amount of time that the EPA believes would be normally necessary for designated facilities to design, install, and startup the control systems identified in component number three. See 40 CFR 60.22a(b)(4). The EPA explains how it proposes to address this component below in section XIV.E. Fifth, and likely most helpful to states when developing their plans in response to the final EG, the EG must include information regarding the "degree of emission limitation achievable through the application of the best system of emission reduction" that has been adequately demonstrated, taking into account the same factors as described in component three (cost, non-air quality health and environmental impact and energy requirements), "and the time within which compliance with standards of performance can be achieved." 40 CFR 60.22a(b)(5). The EPA has included such information in sections XI and XII of this preamble and the TSD located at Docket ID No. EPA-HQ-OAR-2021-0317 as well as in section XIV.E of this preamble. In identifying the degree of achievable emission limitation, the EPA may subcategorize, that is to "specify different degrees of emission limitation or compliance times or both for different sizes, types, and classes of designated facilities when costs of control, physical limitations, geographical location, or similar factors make subcategorization appropriate." Id. As explained in XI and XII the EPA has chosen to exercise that discretion to subcategorize within the draft EG for certain emission points, such as for pneumatic controllers. Sixth, and last, the EG is to include any other information not contemplated by the five other components that the EPA "determines may contribute to the formulation of State plans." This section includes such information and guidance specifically designed to assist states in developing their plans under CAA 111(d) for these draft EG.
C. Establishing Standards of Performance in State Plans
While the EPA has the authority and responsibility to determine the BSER and the degree of limitation achievable through application of the BSER, CAA section 111(d)(1) provides that states shall submit to the EPA plans that establish standards of performance for designated facilities (i.e., existing sources) and provide for implementation and enforcement of such standards. In light of the statutory text, and as reflected in the technical completeness criteria in the EPA's implementing regulations (explained below), state plans implementing the EG should include requirements and detailed information related to two key aspects of implementation: establishing standards of performance for designated facilities and providing measures that implement and enforce such standards.
Establish Standards of Performance for Designated Facilities. As an initial matter, a state must identify existing facilities within its borders that meet the applicability requirements in the final EG and are thereby considered a "designated facility" under the EG. Then, states are required to establish standards of performance for the identified designated facilities. There is a fundamental requirement under CAA section 111(d) that a state's standards of performance reflect the degree of emission limitation achievable through the application of the BSER, which derives from the definition of "standard of performance" in CAA section 111(a)(1). The statute further requires the EPA to permit states, in applying a standard of performance, to consider a source's remaining useful life and other factors. Accordingly, based on both the mandatory and discretionary aspects of CAA section 111(d), a certain level of process is required of state plans: namely, the standards of performance must reflect the degree of emission limitation achievable through application of the BSER, and if the state chooses, the consideration of remaining useful life and other factors in applying a standard of performance to a designated facility.
      For this 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 of performance that states may use in the development of state plans for specific emission points. The EPA believes that the presumptive standards of performance included in the EG will provide states with the level of stringency that the EPA would require to approve a state plan. Put another way, the EPA is choosing to format this EG such that if a state chooses to adopt the presumptive standards as the standards of performance in their state plan, then the EPA believes that such plan could be approved as meeting the requirements of CAA section 111(d) and the finalized EG, assuming the plan meets all other applicable requirements. In this way, the presumptive standards included in the EG serve a similar purpose as a model rule because they are intended to assist states in developing their plan submissions by providing the states with a starting point for their standards that are based on general industry parameters and assumptions. The EPA believes that providing these presumptive standards of performance will create a streamlined approach for states in developing plans and for the EPA in evaluating state plans. Of course, the EPA cannot pre-determine the outcome of a future rulemaking process, and inclusion of these presumptive standards in this EG does not impact the rulemaking process associated with the EPA's review of, and action on, a state plan submission. In its review of state plans, the EPA will consider the information in the final EG (including what EPA publishes in the final EG as the presumptive standards), as well as information submitted by the state and the public. The EPA will evaluate the approvability of all plans through individual notice-and-comment rulemaking processes. 
      As described in sections XI and XII, the EPA is proposing to translate the degree of emission limitation achievable through application of the BSER into presumptive standards for the following designated facilities as shown in Table 20.
TABLE 20: SUMMARY OF PROPOSED EG SUBPART OOOOc PRESUMPTIVE NUMERICAL STANDARDS 
                                       
Designated Facility
Proposed Presumptive Mass-Based Standards in the Draft Emissions Guidelines for GHGs
Storage Vessels: Tank Battery with PTE of 20 tpy or More of Methane
95 percent control
Wet Seal Centrifugal Compressors
95 percent control 
Pneumatic Pumps: Locations Other Than Natural Gas Processing Plants
95 percent control if there is an existing control or process on site. 95 percent control not required if (1) routed to an existing control that achieves less than 95 percent or (2) it is technically infeasible to route to the existing control device or process 

      For these designated facilities, state plans would generally be expected to establish standards of performance that reflect these numerical presumptive standards, if included in the final EG. Further, for these designated facilities, the EPA is proposing to require that the standards of performance be expressed in the same form as the numerical presumptive standards set forth in Table 20. For example, for storage vessels that are part of a tank battery with a PTE of 20 tpy or more of methane, the EPA is proposing a numerical presumptive standard of 95-percent control. Accordingly, if finalized as proposed, states would be required to submit a plan that includes numerical standards of performance for these designated facilities expressed in the same form as the presumptive standard of 95 percent control. As described in this proposal and the associated supporting materials in the docket, the EPA has extensively and rigorously performed technical analyses in order to determine the appropriate proposed BSER for each set of designated facilities. The form of the numerical expression of the degrees of emission limitation achievable through application of the BSERs, and the associated presumptive standards, are a result of these technical analyses. The EPA believes that requiring states to maintain the same form of numerical standard in their plans will preserve the integrity of the BSERs and avoid analytic issues that are likely to arise if EPA is required to determine whether a different form of numerical standard submitted by a state has the same level of stringency as the final EG. Accordingly, having a uniform form of standard of performance will help streamline the states' development of their plans, as well as the EPA's review of those plans, since there will be fewer variables to evaluate in the development and review of each standard of performance. The EPA solicits comment on its proposal to require state plans to include numerical standards of performance for these designated facilities that are in the same form as the numerical presumptive standards, and whether EPA should additionally allow states to include a different form of numerical standards for these facilities so long as states demonstrate the equivalency of such standards to the level of stringency required under the final EG.
      For the following designated facilities, the EPA is proposing to translate the degree of emission limitation achievable through application of the BSER into the presumptive standards shown in Table 21. 
TABLE 21: SUMMARY OF PROPOSED EG SUBPART OOOOc PRESUMPTIVE NON-NUMERICAL STANDARDS 
Designated Facility
Proposed Presumptive Non-Numerical Standards in the Draft Emissions Guidelines for GHGs
Fugitive Emissions: Well Sites 

>=15 tpy methane
Quarterly OGI monitoring following Appendix K. (Optional quarterly EPA Method 21 monitoring with 500 ppm defined as a leak).

First attempt at repair within 30 days of finding fugitive emissions. Final repair within 30 days of first attempt.
Fugitive Emissions: Well Sites 

>=5 to <15 tpy methane
Semiannual OGI monitoring following Appendix K. (Optional semiannual EPA Method 21 monitoring with 500 ppm defined as a leak).

First attempt at repair within 30 days of finding fugitive emissions. Final repair within 30 days of first attempt.
Fugitive Emissions: Well Sites 

>0 to <5 tpy methane
Calculate and maintain record of baseline methane emissions.
Fugitive Emissions: Compressor Stations
Quarterly OGI monitoring following Appendix K. (Optional quarterly EPA Method 21 monitoring with 500 ppm defined as a leak).

First attempt at repair within 30 days of finding fugitive emissions. Final repair within 30 days of first attempt.
Pneumatic Controllers: Subcategory 1 (at sites with onsite power available)
VOC and methane emission bleed rate of zero
Pneumatic Controllers: Subcategory 2 (at sites where onsite power is not available -continuous bleed natural gas driven)
Natural gas bleed rate no greater than 6 scfh
Pneumatic Controllers: Subcategory 2 (at sites where onsite power is not available -intermittent natural gas driven)
Monitor and repair through fugitives program

Pneumatic Controllers: Natural Gas Processing Plants
Zero natural gas bleed rate
Reciprocating Compressors 
Rod packing changeout based on annual monitoring (when measured leak rate exceeds 2 scfm) 
Pneumatic Pumps: Natural Gas Processing Plants
Zero natural gas emissions
Equipment Leaks at Gas Plants
Bimonthly OGI LDAR program (NSPS VVa as optional alternative)
      
      The EPA's implementing regulations at 40 CFR 60.24a(b) require that standards of performance shall either be based on allowable rate or limit of emissions, except when the EPA identifies cases in an EG where it would not be feasible to prescribe or enforce a rate or limit. Put another way, 40 CFR 60.24a(b) permits the EPA to identify cases where it is not feasible for states to prescribe or enforce a numerical standard, and in those cases the EPA can include non-numerical emissions limitations such as design, equipment, work practice, or operational standards, or a combination thereof, in the EG. See also definition of "standard of performance" in 40 CFR 60.21a(f). This authority in the context of the EG is akin to the EPA's authority under CAA section 111(h) to prescribe non-numerical standards where the Administrator determines it is not feasible to prescribe or enforce a numerical standard of performance. Where the EPA finalizes EG that authorize design, equipment, work practice, or operational standard, or a combination thereof, the state "plan shall, to the degree possible, set forth the emission reductions achievable by implementation of such standards, and may permit compliance by the use of equipment determined by the State to be equivalent to that prescribed" by the state plan. See 40 CFR 60.24a(b). 
      For the designated facilities listed in Table 21 the EPA has determined that it is not feasible to prescribe or enforce a numerical standard. As such, for these designated facilities, the EPA is proposing presumptive standards that are comprised of design, equipment, work practice, and/or operational standards. For these designated facilities, states are generally expected to establish the same non-numerical presumptive standards in Table 21. If states do not incorporate the presumptive standards included in the final EG into their state plan, but instead wish to utilize a different design, equipment, work practice, and/or operational standard for any of the designated facilities listed in Table 21, then the EPA is proposing to require that the state include in its plan a demonstration of how that standard will achieve a reduction in methane emissions at least equivalent to the reduction in methane emissions achieved by application of the presumptive standards included in the final EG. Such a demonstration should take into account, among other factors, the timelines for compliance. The EPA believes that this requirement is consistent with the AMEL provision in CAA section 111(h)(3), which requires a demonstration that any alternative "will achieve a reduction in emissions . . . at least equivalent to the reduction in emissions" achieved by EPA's standard, and the technical completeness criteria found at 40 CFR 60.27a(g)(3)(iv), which requires that state plans must include a "demonstration that the State plan submittal is projected to achieve emissions performance under the applicable EG."
      To the extent that a state determines the presumptive standards in the final EG are not reasonable for a particular designated facility due to remaining useful life and other factors, the statute requires that the EPA's regulations under CAA section 111(d) permit states to consider such factors in applying a standard of performance. As such, the EPA's implementing regulations at 40 CFR 60.24a(e) allow states to consider remaining useful life and other factors to apply a less stringent standard of performance to a designated facility or class of facilities if one or more demonstrations are made. These demonstrations include unreasonable cost of control resulting from plant age, location, or basic process design; physical impossibility of installing necessary control equipment; or other factors specific to the facility (or class of facilities) that make application of a less stringent standard or final compliance time significantly more reasonable. The implementing regulations also clarify that, absent such a demonstration, the state's standards of performance must be "no less stringent than the corresponding" EG. See 40 CFR 60.24a(c).
      The EPA intends to provide further clarification on the general process and requirements for accounting for remaining useful life and other factors, including on the reasonableness aspect of the required demonstration, via a rulemaking to amend the implementing regulations in the near future. However, the EPA also recognizes that the oil and natural gas industry is unique such that the general approach to considering remaining useful life and other factors in the implementing regulations may not be an ideal fit. For example, the sheer number and variety of designated facilities in the oil and natural gas industry could make a source-specific (or even a class-specific) evaluation of remaining useful life and other factors extremely difficult and burdensome for states that want to undertake a demonstration. In addition, these designated facilities generally have fewer major capital expenses compared with other industries for which EPA has previously issued EG under CAA section 111(d), and many of the proposed presumptive standards generally take the form of design, equipment, work practice, or operational standards rather than numerical emission limitations. Given these facts, the EPA believes that it would likely be difficult for states to determine that the presumptive standards are not reasonable for the vast majority of designated facilities. The EPA is soliciting comment on these observations, and any other facts and circumstances that are unique to the oil and natural gas industry that could impact the remaining-useful-life-and-other-factors demonstration. The EPA is also soliciting comment as to whether the Agency should include specific provisions regarding the consideration of remaining useful life and other factors in this EG that would supplement or supersede the general provisions in the implementing regulations.
      The EPA intends to provide further clarification on the general process and requirements for accounting for remaining useful life and other factors, including on the reasonableness aspect of the required demonstration, via a rulemaking to amend the implementing regulations in the near future. However, the EPA also recognizes that the oil and natural gas industry is unique such that the general approach to considering remaining useful life and other factors in the implementing regulations may not be an ideal fit. For example, the sheer number and variety of designated facilities in the oil and natural gas industry could make a source-specific (or even a class-specific) evaluation of remaining useful life and other factors extremely difficult and burdensome for states that want to undertake a demonstration. In addition, the presumptive standards for these designated facilities generally entail fewer major capital expenses compared with other industries for which EPA has previously issued EG under CAA section 111(d), and many of the proposed presumptive standards generally take the form of design, equipment, work practice, or operational standards rather than numerical emission limitations. Further, in proposing the presumptive standards for existing source, the EPA has deliberately crafted subcategories and included certain flexibilities (e.g., in cases of technical infeasibility) such that the EPA believes the presumptive standards should be achievable and cost-effective for a wide variety of facilities across the source category. Given these facts, the EPA believes that it would likely be difficult for states to demonstrate that the presumptive standards are not reasonable for the vast majority of designated facilities. The EPA is soliciting comment on these observations, and any other facts and circumstances that are unique to the oil and natural gas industry that could impact the remaining-useful-life-and-other-factors demonstration. The EPA is also soliciting comment as to whether the Agency should include specific provisions regarding the consideration of remaining useful life and other factors in this EG that would supplement or supersede the general provisions in the implementing regulations.
      To the extent a state chooses to submit a plan that includes standards of performance that are more stringent than the requirements of the final EG, states have the authority to do so under CAA section 116, and the EPA has the authority to approve such plans and render them Federally enforceable if all applicable requirements are met. Union Electric Co. v. EPA, 427 U.S. 246, (1976). See also 40 CFR 60.24a(f). The EPA acknowledges that in the Affordable Clean Energy (ACE) rule, it previously took the position that Union Electric does not control the question of whether CAA section 111(d) state plans may be more stringent than Federal requirements. The ACE rule took this position on the basis that Union Electric on its face applies only to CAA section 110, and that it is potentially salient that CAA section 111(d) is predicated on specific technologies whereas CAA section 110 gives states broad latitude in the measures used for attaining the National Ambient Air Quality Standards (NAAQS). 84 FR 32559-61. The EPA no longer takes this position. Upon further evaluation, the EPA believes that because of the structural similarities between CAA sections 110 and 111(d), CAA section 116 as interpreted by Union Electric requires the EPA to approve CAA section 111(d) state plans that are more stringent than required by the EG if the plan is otherwise is compliance with all applicable requirements. See FCC v. Fox Television Stations, Inc., 556 U.S. 502 (2009). The D.C. Circuit in Union Electric rejected a construction of CAA sections 110 and 116 that measures more stringent than those required to attain the NAAQS cannot be approved into a Federally enforceable State Implementation Plan (SIP) but must be adopted and enforced only as a matter of state law. Id. at 263-64. While the BSER and the NAAQS are distinct from one another in that the former is technology-based and the latter is based on ambient air quality, both CAA sections 111(d) and 110 are structurally similar in that states must adopt and submit to the EPA plans which include requirements to meet the objectives of each respective section. Requiring states to enact and enforce two sets of standards, one that is a Federally approved CAA section 111(d) plan and one that is a stricter state plan, runs directly afoul of the court's holding that there is no basis for interpreting CAA section 116 in such manner. Therefore, the EPA interprets CAA sections 111(d) and 116 as allowing states to include, and the EPA to approve, more stringent standards of performance in state plans. The EPA notes that its authority is constrained to approving measures which comport with applicable statutory and regulatory requirements. For example, CAA section 111(d) only contemplates that state plans include requirements for designated facilities, therefore the EPA believes it does not have the authority to approve and render Federally enforceable measures on other entities.
      The EPA is also aware that in the context of regulating the oil and natural gas industry many states have existing programs they may want to leverage for purposes of satisfying their CAA section 111(d) state plan obligations. The EPA anticipates providing information on ways in which state plans can accommodate existing state programs to the extent such programs are at least as stringent as the requirement of the final EG. Consistent with the proposed presumptive standards, the EPA proposes that a state plan which relies on an existing state program must still establish standards of performance that are in the same form as the presumptive standards. The EPA solicits comment on whether states relying on existing programs should be authorized to include a different form of standard in their plans so long as they demonstrate the equivalency of such standards to the level of stringency required under the final EG. The EPA proposes to require that, in situations where a state wishes to rely on state programs (statutes and/or regulations) that pre-date finalization of the EG proposed in this document to satisfy the requirements of CAA section 111(d), the state plan should identify which aspects of the existing state programs are being submitted for approval as Federally enforceable requirements under the plan, and include a detailed explanation and analysis of how the relied upon existing state programs are at least as stringent as the requirements of the final EG. The EPA notes that the completeness criteria in 40 CFR 60.27a(g) requires a copy of the actual state law/regulation or document submitted for approval and incorporation into the state plan. Put another way, where a state is relying on an existing state program for its plan, a copy of the pre-existing state statute or regulation underpinning the program would be required by this criterion, and would be a critical component of the EPA's evaluation of the approvability of the plan. The EPA also solicits comment on various ways in which existing state programs can be adopted into state plans. Particularly, the EPA is interested in how existing state programs that regulate both designated facilities and sources not considered as designated facilities under this EG could be tailored for a state plan to meet the requirements of CAA section 111(d).
      Providing Measures that Implement and Enforce Such Standards. As part of establishing standards of performance, state plans must also include compliance schedules for those standards. See 40 CFR 60.24a(a). Section XIV.E, explains how the EPA is proposing to approach compliance schedules. The EPA's implementing regulations require that, except where the state chooses to account for remaining useful life and other factors, state plans shall require final compliance as expeditiously as practicable, but no later than the compliance times specified in the EG. See 40 CFR 60.24a(c). Where a state applies a less stringent standard of performance because of remaining useful life and other factors, the compliance schedule must appropriately comport with that standard. 
      In addition to establishing standards of performance and compliance schedules, state plans must also include, adequately document, and demonstrate the methods employed to implement and enforce the standards of performance such that the EPA can review and identify measures that assure transparent and verifiable implementation. As part of ensuring that regulatory obligations appropriately meet statutory requirements such as enforceability, the EPA has historically and consistently required that obligations placed on sources be quantifiable, non-duplicative, permanent, verifiable, and enforceable. See 40 CFR 60.27a(g)(3)(vi). In accordance with the EPA's implementing regulations, standards of performance required for designated facilities as part of a state plan to implement the EG proposed here must be non-duplicative, permanent, verifiable, and enforceable. The EPA acknowledges that it may not be feasible to quantify certain non-numerical standards of performance included in the EG. As such, the EPA is proposing that standards of performance for this EG be quantifiable to the extent feasible. A state plan implementing the EG should include information adequate to support a determination by the EPA that the plan meets these requirements. Additionally, states must include appropriate monitoring, reporting, and recordkeeping requirements to ensure that state plans adequately provide for the implementation and enforcement of standards of performance. For designated facilities where the EPA's presumptive standards include associated monitoring, reporting, and/or recordkeeping requirements, the EPA has determined that such requirements are necessary to ensure compliance. Thus, for those designated facilities, the EPA is proposing to require that the standards of performance established by states maintain the same monitoring, reporting, and recordkeeping requirements, or equivalent requirements. For example, the EG's presumptive standards for fugitives monitoring at well sites includes requirements for owners and operators to maintain records and submit reports that demonstrate compliance with the monitoring and repair provisions. As such, the EPA is proposing that the portion of the state plan which establishes standards of performance for that designated facility also includes requirements for owners and operators to maintain records and submit reports that demonstrate compliance with the monitoring and repair provisions. Where a state plan adopts standards of performance that differ from the presumptive standards, the plan may accordingly include different monitoring, reporting, and recordkeeping requirements than those in the presumptive standards, but such requirements must be appropriate for the implementation and enforcement of the standards. For components of a state plan that differ from any presumptively approvable aspects of the final EG, the EPA will review the approvability of such components through notice and comment rulemaking.
      Emissions Inventories. The implementing regulations at 40 CFR 60.25a contain generally applicable requirements for emission inventories, source surveillance, and reports. State plans must include provisions to meet these requirements as well. Section 60.25a further specifies that such data shall be summarized in the plan, and emission rates of designated pollutants from designated facilities shall be correlated with applicable standards of performance. Typically, the EPA would expect that state plans would present this information on a source-specific or unit-specific level. However, the EPA recognizes that due to the very large number of existing oil and natural gas sources, and the frequent change of configuration and/or ownership, that it may not be practical to require states to compile this information in the same way that is typically expected for other industries under other EG. Therefore, the EPA is soliciting comment on whether to supersede the requirements of 40 CFR 60.25a(a) for purposes of this EG. The EPA may supersede any requirement in its implementing regulations for CAA section 111(d) if done so explicitly in the EG. See 40 CFR 60.20a(a)(1). Specially, for the reasons explained previously, the EPA believes that in this context it could be difficult for the state plans to include "an inventory of all designated facilities, including emission data for the designated pollutants and information related to emissions as specified in appendix D to this part" as required by the first sentence in 40 CFR 60.25a(a). The EPA understands that states may not have such an inventory of all designated facilities already available and that creating such an inventory could be resource intensive. Likewise, the EPA understands that states may not have site-specific emissions data for each designated facility, and that creating such an inventory could also be very resource intensive. The EPA does not believe that such detailed information is necessary for states to develop standards of performance, and that standards of performance could be developed with a different type of emissions inventory data. Therefore, in order to avoid the potential burden that could be imposed by applying 40 CFR 60.25a(a) as written to this EG, the EPA is soliciting comment on whether the Agency should supersede the requirements of 40 CFR 60.25a(a) for purposes of this EG, and replace that requirement with a different emissions inventory requirement that seeks to represent the same general type of information but allows states to utilize existing inventories and emissions data. An example of an inventory that could be leveraged, and on which the EPA specifically solicits comment, is the GHGRP. The EPA envisions a superseding requirement that would not impose such a resource intensive burden on states by allowing use of an inventory of GHG emissions data and operational data for designated facilities during the most recent calendar year for which data is available at the time of state plan development and/or submission. The emissions inventory data submitted for this purpose could be derived from the GHGRP, and/or other available existing inventory information available to the state. The EPA recognizes that in this situation the facility definitions used for purposes of compiling the emissions inventory data might not be fully aligned with the designated facilities in the EG, and that it is possible that there could be designated facilities under this EG that are not required to report under the emissions inventory program being relied upon. Further, the EPA recognizes that the GHGRP may include a reporting threshold and/or utilize emission factors in a different manner than the EG. The EPA solicits comment on whether it is appropriate to utilize or supersede 40 CFR 60.25a(a) for purposes of this EG. Specifically, the EPA solicits comment on the practicality of states compiling an inventory for all designated facilities and on what reasonable alternatives may be more practical. 
      Meaningful Engagement. In establishing standards of performance and developing the state plan, the state rulemaking process must meet the minimum public participation requirements of the implementing regulations as applicable to these guidelines, including a public hearing and meaningful engagement with all members of the public, including vulnerable communities. In sections VI and VII of this preamble the EPA addresses the environmental justice considerations, implications and stakeholder outreach the agency is taking to help ensuring vulnerable communities are not disproportionately impacted by this rule. The EPA intends to propose meaningful engagement requirements in state plan development as part of the upcoming rulemaking addressing the vacated timing provisions within 40 CFR 60, subpart Ba. 
D. Components of State Plan Submission
	Under CAA section 111(d)(2), the EPA has an obligation to determine whether each state plan is "satisfactory." Therefore, in addition to identifying the components that the EG must include, the EPA's implementing regulations for CAA section 111(d) identify additional components that a state plan must include. Many of these requirements are found in 40 CFR 60.23a, 60.24a, 60.25a, and 60.26a. These provisions include requirements for components such as the following: procedures a state must go through for adopting a plan before submitting it to the EPA; the stringency of standards of performance and compliance timelines; emission inventories, reporting, and recordkeeping; and, the legal authority a state must show in adopting a plan. These requirements are also generally contained in a list of required state plan elements, referred to as the state plan completeness criteria, found at 40 CFR 60.27a(g)(2)-(3). If the EPA determines that a submitted plan does not meet these criteria then the state is treated as not submitting a plan and the EPA has a duty to promulgate a Federal plan for that state. See CAA section 111(d)(2)(A) and 40 CFR 60.27a(g)(1). If the EPA determines a plan submission is complete, such determination does not reflect a judgment on the eventual approvability of the submitted portions of the plan, which instead must be made through notice-and-comment rulemaking. The completeness criteria do not apply to states without any designated facilities because these states are directed to submit to the Administrator a letter of negative declaration certifying that there are no designated facilities, as defined by the EPA's emissions guidelines, located within the state. See 40 CFR 60.23a(b). No plan is required for states that do not have any designated facilities. Designated facilities located in states that mistakenly submit a letter of negative declaration would be subject to a Federal plan until a state plan regulating those facilities becomes approved by the EPA.
	The EPA established nine administrative and six technical criteria for complete state plans under CAA section 111(d). See 40 CFR 60.27a(g)(2)-(3). If a state plan does not include even one of these criteria, then the state plan may be deemed incomplete by the EPA. States that are familiar with the SIP submittal process under CAA section 110 will be familiar with the completeness criteria found in 40 CFR Part 51 Appendix V. While the completeness criteria for state plan submittals found at 40 CFR 60.27a(g)(2)-(3) is somewhat similar to the SIP submittal criteria in Appendix V, it is not exactly the same. As such, even states that are familiar with the SIP submittal process under CAA section 110 are strongly encouraged to review the completeness criteria in 40 CFR 60.27a(g)(2)-(3) as well as the other state plan requirements found in 40 CFR 60.23a, 60.24a, 60.25a, and 60.26a early in their planning process. 
      In short, the administrative completeness criteria require that the state's plan include a formal submittal letter and a copy of the actual state regulations themselves, as well as evidence that the state has legal authority to adopt and implement the plan, actually adopted the plan, followed state procedural laws when adopting the plan, gave public notice of the changes to state law, held public hearing(s) if applicable, and responded to state-level comments. For a detailed description regarding the public hearing requirement, see 40 CFR 60.23a. For a detailed description of what the state plan must include in terms of evidence that the state has legal authority to adopt and implement the plan, see 40 CFR 60.26a. States are strongly encouraged to review the state plan requirements included in 40 CFR 60.23a and 60.26a in conjunction with the administrative completeness criteria in 40 CFR 60.27a.
      The technical criteria require that the state's plan identify the designated facilities, the standards of performance, the geographic scope of the plan, monitoring, recordkeeping and reporting requirements (both for facilities to ensure compliance and for the state to ensure performance of the plan as a whole), and compliance schedules.  The technical criteria further require that the state demonstrate that the plan is projected to achieve emission performance under the EG and that each emission standard is quantifiable, non-duplicative, permanent, verifiable, and enforceable. As previously described, it may not be feasible to quantify certain non-numerical standards of performance. The EPA is proposing to require states demonstrate that each standard of performance is quantifiable, as feasible. For a detailed description of the state plan requirements regarding standards of performance, see section XIV.C and 40 CFR 60.24a. 
      In addition to these technical criteria, 40 CFR 60.25a(a) requires that state plans include certain emissions data for the designated facilities. As explained previously, the EPA is soliciting comment on superseding that requirement for this EG. Further, 60.25a provides a detailed description of what the state plan is required to include in terms of certain compliance monitoring and reporting. States are strongly encouraged to review the state plan requirements included in 40 CFR 60.24a and 60.25a in conjunction with the technical completeness criteria in 40 CFR 60.27a.
E. Timing of State Plan Submissions and Compliance Times
      The EPA acknowledges that the D.C. Circuit has vacated certain timing provisions within 40 CFR 60, subpart Ba. Am. Lung Assoc. v. EPA, 985 F.3d 914, 991 (D.C. Cir. 2021). These provisions include timing requirements for when state plans are due upon publication of a final EG, for EPA's action on a state plan submission, and for EPA's promulgation of a Federal plan. The Agency plans to undertake rulemaking to address the provisions vacated under the court's decision in the near future. We recognize that the public needs to have an opportunity to review and comment on the new timelines that will address these regulatory gaps, including in particular the timeline for state plan submission, and the Agency is committed to publishing this proposed timeline for comment when available.
      In accordance with 40 CFR 60.22a(b)(5), the EPA's EG is to provide information for the development of state plans that includes, among other things, "the time within which compliance with standards of performance can be achieved." The EPA is to propose those compliance times for comment. See 40 CFR 60.25a(c). Each state plan must include compliance schedules that, subject to certain exception, require compliance as expeditiously as practicable but no later than the compliance times included in the relevant EG. Id. at 60.24a(a) and (c). States are free to include compliance times in their plans that are earlier than those included in the final EG. Id. at 40 CFR 60.24a(f)(2). If a state chooses to include a compliance schedule in their plan that extends for a certain period beyond the date required for submittal of the plan, then "the plan must include legally enforceable increments of progress to achieve compliance for each designated facility." Id. at 40 CFR 60.24a(d). To the extent a state accounts for remaining useful life and other factors in applying a less stringent standard of performance (than required by the EPA in the final EG), the state must also include a compliance deadline that it can demonstrate appropriately correlates with that standard.
      The EPA is proposing to require that state plans impose a compliance timeline on designated facilities to require final compliance with the standards of performance as expeditiously as practicable, but no later than two years following the state plan submittal deadline. As explained above, the EPA anticipates proposing a state plan submission deadline in a separate notice. The EPA believes that two years is an appropriate amount of time for designated facilities to ensure compliance based on the EPA's general understanding of the industry and the proposed presumptive standards. However, the EPA recognizes that there are many existing sources in the oil and natural gas industry that would be subject to a state plan if the presumptive standards are finalized in a similar manner as proposed in this document, and that there may be a wide range of configurations that may be present at any given facility. Further, the EPA recognizes that it may be appropriate to require different compliance times for different designated facilities. For example, it may be appropriate to require one compliance schedule for reciprocating compressors and a different compliance schedule for storage vessels. There may not be a one-size-fits-all approach to compliance times that is appropriate for all designated facilities; it may not be appropriate to require a single compliance time. The EPA is soliciting comment on whether a two-year compliance schedule is appropriate for all designated facilities, or whether the EG should require a shorter or longer compliance schedule. The EPA is further soliciting comment on whether it would be appropriate to establish different compliance schedules for different designated facilities, and if so, what are the appropriate timelines for each designated facility. The EPA is soliciting comment on this matter to collect information that might inform different compliance timeline(s) that Agency may propose for comment in the future via a supplemental proposal.
F. EPA Action on State Plans and Promulgation of Federal Plans
     While CAA section 111(d)(1) authorizes states to develop state plans that establish standards of performance and provides states with certain discretion in determining the appropriate standards, CAA section 111(d)(2) provides the EPA a specific oversight role with respect to such state plans. This latter provision authorizes the EPA to prescribe a Federal plan for a state "in cases where the state fails to submit a satisfactory plan." The states must therefore submit their plans to the EPA, and the EPA must evaluate each state plan to determine whether each plan is "satisfactory." The EPA's implementing regulations for CAA section 111(d) accordingly provide procedural requirements for the EPA to make such a determination. See 40 CFR 60.27a.
     Upon receipt of a state plan, the EPA is first required to determine whether the state plan submittal is complete in accordance with the completeness criteria explained above. See 40 CFR 60.27a(g)(1). The EPA would then have a set period of time to act on any state plan that is deemed complete. If the EPA determines that the state plan submission is incomplete, then the state will be treated as not having made the submission, and the EPA would be required to promulgate a Federal plan for the designated facilities in that state. Likewise, if a state does not make any submission then the EPA is required to promulgate a Federal plan. If the EPA does not make an affirmative determination regarding completeness of the state plan submission within a certain amount of time from receiving the state plan, then the submission is deemed complete by operation of law. Id.
     If a state has submitted a complete plan, then the EPA is required to evaluate that plan submission for approvability in accordance with the CAA, EPA's implementing regulations, and the applicable EG. The EPA may approve or disapprove the state plan submission in whole or in part. See 40 CFR 60.27a(b). If the EPA approves the state plan submission, then that state plan becomes Federally enforceable. If the EPA disapproves the required state plan submission, in whole or in part, then the EPA is required to promulgate a Federal plan for the designated facilities in that state via a notice-and-comment rulemaking, and with an opportunity for public hearing. See 40 CFR 60.27a(c) and (f). In either scenario that would give rise to the EPA's duty to promulgate a Federal plan (a finding that a state did not submit a complete plan or a disapproval of a state plan), the EPA would not be required to promulgate the Federal plan if the state corrects the deficiency giving rise to the EPA's duty and the EPA approves the state's plan before promulgating the Federal plan. Requirements regarding the content of a Federal plan are included in 40 CFR 60.27a(e).
G. Tribes and The Planning Process Under CAA Section 111(d)
      Under the Tribal Authority Rule (TAR) adopted by the EPA, tribes may seek authority to implement a plan under CAA section 111(d) in a manner similar to a state. See 40 CFR part 49, subpart A. Tribes may, but are not required to, seek approval for treatment in a manner similar to a state for purposes of developing a tribal implementation plan (TIP) implementing the EG. If a tribe obtains approval and submits a TIP, the EPA will generally use similar criteria and follow similar procedures as those described above for state plans when evaluating the TIP submission, and will approve the TIP if appropriate. The EPA is committed to working with eligible tribes to help them seek authorization and develop plans if they choose. Tribes that choose to develop plans will generally have the same flexibilities available to states in this process. If a tribe does not seek and obtain the authority from the EPA to establish a TIP, the EPA has the authority to establish a Federal CAA section 111(d) plan for areas of Indian country where designated facilities are located. A Federal plan would apply to all designated facilities located in the areas of Indian country covered by the Federal plan unless and until the EPA approves an applicable TIP applicable to those facilities.
XV. Prevention of Significant Deterioration and Title V Permitting                                                                                                                
      In this section, the EPA is addressing how regulation of GHGs under CAA section 111 could have implications for other EPA rules and for permits written under the CAA PSD preconstruction permit program and the CAA title V operating permit program. The EPA is proposing to include provisions in the regulations that explicitly address some of these potential implications, consistent with our experience in prior rules regulating GHGs. The EPA included and explained the basis for similar provisions when promulgating 2016 NSPS OOOOa, as well as the 2015 subpart TTTT NSPS for electric utility generating units. See 81 FR 35823, 35871 (June 3, 2016); 80 FR 64509, 64628 (October 23, 2015). The discussion in these prior rule preambles equally applies to the oil and gas sources subject to NSPS OOOOb and EG OOOOc.
      In summary, in light of the U.S. Supreme Court's decision in Utility Air Regulatory Group v. Environmental Protection Agency, 573 U.S. 302 (2014) (UARG), the EPA may not treat GHGs as an air pollutant for purposes of determining whether a source is a major source (or modification thereof) for the purpose of PSD applicability. Certain portions of the EPA's PSD regulations (specifically, the definition of "subject to regulation") effectively ensure that most sources will not trigger PSD solely by virtue of their GHG emissions. E.g., 40 CFR 51.166(b)(48)(iv), 52.21(b)(49)(iv). However, the EPA's PSD regulations (specifically, the definition of "regulated NSR pollutant") provide additional bases for PSD applicability for pollutants that are regulated under CAA section 111. To address this latter component of PSD applicability, the EPA is proposing to add provisions within the subpart OOOOb NSPS and OOOOc EG to help clarify that the promulgation of GHG standards under section 111 will not result in additional sources becoming subject to PSD based solely on GHG emissions, which would be contrary to the holding in UARG. These provisions will be similar to those in the 2016 NSPS OOOOa and other section 111 rules that regulate GHGs. See, e.g., 40 CFR 60.5360a(b)(1)-(2), 60.5515(b)(1)-(2).
      The EPA understands there are also concerns that if methane were to be subject to regulation as a separate air pollutant from GHGs, sources that emit methane above the PSD thresholds or modifications that increase methane emissions could be subject to the PSD program. To address this concern and for purposes of clarity, the EPA is proposing to adopt regulatory text within subparts OOOOb and OOOOc to clarify that the air pollutant that is subject to regulation is GHGs, even though the standard is expressed in the form of a limitation on emission of methane. This language will be substantially similar to language found in, for example, the 2016 NSPS OOOOa and other rules. See, e.g., 40 CFR 60.5360a(a), 60.5515(a). 
      For sources that are subject to the PSD program based on non-GHG emissions, the CAA continues to require that PSD permits satisfy the best available control technology (BACT) requirement for GHGs. Based on the language in the PSD regulations, the EPA and states may continue to limit the application of BACT to GHG emissions in those circumstances where a new source emits GHGs in the amount of at least 75,000 tpy on a CO2 Eq. basis or an existing major source increases emissions of GHGs by more than 75,000 tpy on a CO2 Eq. basis. See 40 CFR 51.166(b)(48)(iv), 52.21(b)(49)(iv). The proposed revisions to the regulatory text within subparts OOOOb and OOOOc will ensure that this BACT applicability level remains operable to sources of GHGs regulated under CAA section 111, as have similar revisions in prior rules. See, e.g., 40 CFR 60.5360a(b)(1)-(2), 60.5515(b)(1)-(2). This proposed rule will not require any additional revisions to SIPs. 
      Regarding title V, the UARG decision similarly held that the EPA may not treat GHGs as an air pollutant for purposes of determining whether a source is a major source for the purpose of title V applicability. Promulgation of CAA section 111 requirements for GHGs will not result in the EPA imposing a requirement that stationary sources obtain a title V permit solely because such sources emit or have the potential to emit GHGs above the applicable major source thresholds. 
      To be clear, however, unless exempted by the Administrator through regulation under CAA section 502(a), any source, including a "non-major source," subject to a standard or regulation under section 111 is required to apply for, and operate pursuant to, a title V permit that ensures compliance with all applicable CAA requirements for the source, including any GHG-related applicable requirements. This aspect of the title V program is not affected by UARG. The EPA proposes to include an exemption from the obligation to obtain a title V permit for sources subject to NSPS OOOOb and EG OOOOc, unless such sources would otherwise be required to obtain a permit under 40 CFR 70.3(a) or 40 CFR 71.3(a), as the EPA did in NSPS OOOO and OOOOa. See 40 CFR 60.5370, 60.5370a. However, sources that are subject to the CAA section 111 standards promulgated in this rule and that are otherwise required to obtain a title V permit under 40 CFR 70.3(a) or 40 CFR 71.3(a) will be required to apply for, and operate pursuant to, a title V permit that ensures compliance with all applicable CAA requirements, including any GHG-related applicable requirements. 
XVI. Impacts of This Proposed Rule
A. What are the air impacts?
      The EPA projected that, from 2023 to 2035, relative to the baseline, the proposed NSPS and EG will reduce about 21.4 million short tons of methane emissions reductions (480 million tons CO2 Eq.), 6.8 million short tons of VOC emissions reductions, and 210 thousand short tons of HAP emission reductions from facilities that are potentially affected by this proposal. The EPA estimated regulatory impacts beginning in 2023 as it represents the first full year of implementation of the proposed NSPS. The EPA assumes that emissions impacts of the proposed EG will begin in 2026. The EPA estimated impacts through 2035 to illustrate the accumulating effects of this rule over a longer period. The EPA did not estimate impacts after 2035 for reasons including limited information, as explained in the RIA. 
B. What are the energy impacts?
	The energy impacts described in this section are those energy requirements associated with the operation of emission control devices. Potential impacts on the national energy economy from the rule are discussed in the economic impacts section in XVI.D. There will likely be minimal change in emissions control energy requirements resulting from this rule. Additionally, this proposed action continues to encourage the use of emission controls that recover hydrocarbon products that can be used on-site as fuel or reprocessed within the production process for sale. 
C. What are the compliance costs?
      The PV of the regulatory compliance cost associated with this proposed rule over the 2023 to 2035 period was estimated to be $8.9 billion (in 2019 dollars) using a 3-percent discount rate and $7.0 billion using a 7-percent discount rate. The EAV of these cost reductions is estimated to be $0.9 billion per year using a 3-percent discount rate and $0.9 billion per year using a 7-percent discount rate. 
      These estimates do not, however, include the producer revenues associated with the projected increase in the recovery of saleable natural gas. Estimates of the value of the recovered product have been included in previous regulatory analyses as offsetting compliance costs. Using the 2021 Annual Energy Outlook (AEO) projection of natural gas prices to estimate the value of the change in the recovered gas at the wellhead projected to result from the proposed action, the EPA estimated a PV of regulatory compliance costs of the proposed rule over the 2023 to 2035 period of $6.6 billion using a 3-percent discount rate and $5.4 billion using a 7-percent discount rate. The corresponding estimates of the EAV of compliance costs after accounting for the recovery of saleable natural gas were $0.7 billion per year using a 3-percent discount rate and $0.7 billion using a 7-percent discount rate. 
D. What are the economic and employment impacts?
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E. What are the benefits of the proposed standards?	
      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 CH4 emission reductions expected from this proposed rule using the SC-CH4 estimates presented in the Technical Support Document: Social Cost of Carbon, Methane, and Nitrous Oxide Interim Estimates under EO13990 (IWG 2021). These SC-CH4 estimates are interim values developed under EO 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.
      The EPA estimated the PV of the climate benefits over the 2023 to 2035 period to be $29 billion at a 3-percent discount rate. The EAV of these benefits is estimated to be $2.9 billion per year at a 3-percent discount rate. These values represent only a partial accounting of climate impacts from methane emissions and do not account for health effects of ozone exposure from the increase in methane emissions.
      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, PM2.5, 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 sensitivity analysis in Appendix B of the Regulatory Impact Analysis 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 sensitivity analysis in the estimate of benefits (and net benefits) projected from this proposal. 
XV. Statutory and Executive Order Reviews 
      Additional information about these statutes and EOs can be found at 
https://www.epa.gov/laws-regulations/laws-and-executive-orders.
A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review 
      This proposed action is an economically significant regulatory action that was submitted to the OMB for review. Any changes made in response to OMB recommendations have been documented in the docket. The EPA prepared an analysis of the potential costs and benefits associated with this action. This analysis, "Regulatory Impact Analysis for the Proposed Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review", is available in the docket and describes in detail the EPA's assumptions and characterizes the various sources of uncertainties affecting the estimates below. 
B. Paperwork Reduction Act (PRA)
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C. Regulatory Flexibility Act (RFA)
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D. Unfunded Mandates Reform Act (UMRA)
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E. Executive Order 13132: Federalism
      This action does not have Federalism implications. It will not have substantial direct effects on the states, on the relationship between the federal government and the states, or on the distribution of power and responsibilities among the various levels of government. However, in the spirit of EO 13132 and consistent with the EPA policy to promote communications between the EPA and state and local governments, the EPA specifically solicits comment on the proposed rule from state and local officials.
F. Executive Order 13175: Consultation and Coordination with Indian Tribal Governments
      This action has tribal implications. However, it will neither impose substantial direct compliance costs on Federally recognized tribal governments, nor preempt tribal law, and does not have substantial direct effects on the relationship between the Federal government and Indian tribes or on the distribution of power and responsibilities between the Federal government and Indian tribes, as specified in EO 13175. 65 FR 67249 (November 9, 2000). The majority of the designated facilities impacted by proposed NSPS and EG on tribal lands are owned by private entities, and tribes will not be directly impacted by the compliance costs associated with this rulemaking. There would only be tribal implications associated with this rulemaking in the case where a unit is owned by a tribal government or in the case of the NSPS, a tribal government is given delegated authority to enforce the rulemaking. Tribes are not required to develop plans to implement the EG under CAA section 111(d) for designated existing sources. The EPA notes that this proposal does not directly impose specific requirements on designated facilities, including those located in Indian country, but before developing any standards for sources on tribal land, the EPA would consult with leaders from affected tribes.
      Consistent with previous actions affecting the Crude Oil and Natural Gas source category, there is significant tribal interest because of the growth of the oil and natural gas production in Indian country. Consistent with the EPA Policy on Consultation and Coordination with Indian Tribes, the EPA will engage in consultation with tribal officials during the development of this action.
G. Executive Order 13045: Protection of Children from Environmental Health Risks and Safety Risks
      This action is subject to EO 13045 (62 FR 19885, April 23, 1997) because it is an economically significant regulatory action as defined by EO 12866, and the EPA believes that the environmental health or safety risk addressed by this action has a disproportionate effect on children. Accordingly, the agency has evaluated the environmental health and welfare effects of climate change on children. GHGs, including methane, contribute to climate change and are emitted in significant quantities by the oil and gas industry. The EPA believes that the GHG emission reductions resulting from implementation of these proposed standards and guidelines, if finalize will further improve children's health. The assessment literature cited in the EPA's 2009 Endangerment Findings concluded that certain populations and life stages, including children, the elderly, and the poor, are most vulnerable to climate-related health effects. The assessment literature since 2009 strengthens these conclusions by providing more detailed findings regarding these groups' vulnerabilities and the projected impacts they may experience. These assessments describe how children's unique physiological and developmental factors contribute to making them particularly vulnerable to climate change. Impacts to children are expected from heat waves, air pollution, infectious and waterborne illnesses, and mental health effects resulting from extreme weather events. In addition, children are among those especially susceptible to most allergic diseases, 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 detailed information on the impacts of climate change to human health and welfare is provided in section III of this preamble.
H. Executive Order 13211: Actions Concerning Regulations that Significantly Affect Energy Supply, Distribution, or Use
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I. National Technology Transfer and Advancement Act (NTTAA) 
      This proposed action for NSPS OOOOb and EG OOOOc involves technical standards. Therefore, the EPA conducted searches for the Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review through the Enhanced National Standards Systems Network (NSSN) Database managed by the American National Standards Institute (ANSI). Searches were conducted for EPA Methods 1, 1A, 2, 2A, 2C, 2D, 3A, 3B, 3C, 4, 6, 10, 15, 16, 16A, 18, 21, 22, and 25A of 40 CFR part 60 Appendix A. No applicable voluntary consensus standards were identified for EPA Methods 1A, 2A, 2D, 21, and 22 and none were brought to its attention in comments. All potential standards were reviewed to determine the practicality of the voluntary consensus standards (VCS) for this rule. Two VCS were identified as an acceptable alternative to EPA test methods for the purpose of this proposed rule. First, ANSI/ASME PTC 19 - 10 - 1981, Flue and Exhaust Gas Analyses (Part 10) (manual portions only and not the instrumental portion) was identified to be used in lieu of EPA Methods 3B, 6, 6A, 6B, 15A and 16A. This standard includes manual and instructional methods of analysis for carbon dioxide, carbon monoxide, hydrogen sulfide, nitrogen oxides, oxygen, and sulfur dioxide. Second, ASTM D6420 - 99 (2010), ``Test Method for Determination of Gaseous Organic Compounds by Direct Interface Gas Chromatography/ Mass Spectrometry'' is an acceptable alternative to EPA Method 18 with the following caveats, only use when the target compounds are all known and the target compounds are all listed in ASTM D6420 as measurable. ASTM D6420 should never be specified as a total VOC Method. (ASTM D6420 - 99 (2010) is not incorporated by reference in 40 CFR part 60.) The search identified 19 VCS that were potentially applicable for this proposed rule in lieu of EPA reference methods. However, these have been determined to not be practical due to lack of equivalency, documentation, validation of data and other important technical and policy considerations. For additional information, please see the September XX, 2021, memo titled, ``Voluntary Consensus Standard Results for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review'' in the public docket. The EPA plans to propose the regulatory language for NSPS OOOOb and EG OOOOc through a supplemental action. At that time, the EPA will include any appropriate incorporation by reference in accordance with requirements of 1 CFR 51.5 as discussed below. The EPA anticipates that the following ten standards are incorporated by reference. 
      :: ASTM D86 - 96, Distillation of Petroleum Products (Approved April 10, 1996) covers the distillation of natural gasolines, motor gasolines, aviation gasolines, aviation turbine fuels, special boiling point spirits, naphthas, white spirit, kerosines, gas oils, distillate fuel oils, and similar petroleum products, utilizing either manual or automated equipment. 
      :: ASTM D1945 - 03 (Reapproved 2010), Standard Test Method for Analysis of Natural Gas by Gas Chromatography covers the determination of the chemical composition of natural gases and similar gaseous mixtures within a certain range of composition. This test method may be abbreviated for the analysis of lean natural gases containing negligible amounts of hexanes and higher hydrocarbons, or for the determination of one or more components. 
      :: ASTM D3588 - 98 (Reapproved 2003), Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density of Gaseous Fuel covers procedures for calculating heating value, relative density, and compressibility factor at base conditions for natural gas mixtures from compositional analysis. It applies to all common types of utility gaseous fuels. 
      :: ASTM D4891 - 89 (Reapproved 2006), Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion covers the determination of the heating value of natural gases and similar gaseous mixtures within a certain range of composition. 
      :: ASTM D6522 - 00 (Reapproved December 2005), Standard Test Method for Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in Emissions from Natural Gas-Fired Reciprocating Engines, Combustion Turbines, Boilers, and Process Heaters Using Portable Analyzers covers the determination of nitrogen oxides, carbon monoxide, and oxygen concentrations in controlled and uncontrolled emissions from natural gas-fired reciprocating engines, combustion turbines, boilers, and process heaters. 
      :: ASTM E168 - 92, General Techniques of Infrared Quantitative Analysis covers the techniques most often used in infrared quantitative analysis. Practices associated with the collection and analysis of data on a computer are included as well as practices that do not use a computer. 
      :: ASTM E169 - 93, General Techniques of Ultraviolet Quantitative Analysis (Approved May 15, 1993) provide general information on the techniques most often used in ultraviolet and visible quantitative analysis. The purpose is to render unnecessary the repetition of these descriptions of techniques in individual methods for quantitative analysis. 
      :: ASTM E260 - 96, General Gas Chromatography Procedures (Approved April 10, 1996) is a general guide to the application of gas chromatography with packed columns for the separation and analysis of vaporizable or gaseous organic and inorganic mixtures and as a reference for the writing and reporting of gas chromatography methods. 
      :: ASME/ANSI PTC 19.10 - 1981, Flue and Exhaust Gas Analyses [Part 10, Instruments and Apparatus] (Issued August 31, 1981) covers measuring the oxygen or carbon dioxide content of the exhaust gas. 
      :: EPA - 600/R - 12/531, EPA Traceability Protocol for Assay and Certification of Gaseous Calibration Standards (Issued May 2012) is mandatory for certifying the calibration gases being used for the calibration and audit of ambient air quality analyzers and continuous emission monitors that are required by numerous parts of the CFR. 
      The EPA determined that the ASTM and ASME/ANSI standards, notwithstanding the age of the standards, are reasonably available because it they are available for purchase from the following addresses: American Society for Testing and Materials (ASTM), 100 Barr Harbor Drive, Post Office Box C700, West Conshohocken, PA 19428 - 2959; or ProQuest, 300 North Zeeb Road, Ann Arbor, MI 48106 and the American Society of Mechanical Engineers (ASME), Three Park Avenue, New York, NY 10016 - 5990. The EPA determined that the EPA standard is reasonably available because it is publicly available through the EPA's Web site: http://nepis.epa.gov/Adobe/PDF/ P100EKJR.pdf.
J. Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations 
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List of Subjects in 40 CFR Part 60
	Environmental protection, Administrative practice and procedure, Air pollution control, Reporting and recordkeeping requirements.

__________________________________
Michael S. Regan,

Administrator.