Document ID: EPA-HQ-OAR-2021-0317-1460
Agency: epa
Document Type: Proposed Rule
Title: Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review
Posted Date: 2022-12-06T05:00Z

[Federal Register Volume 87, Number 233 (Tuesday, December 6, 2022)]
[Proposed Rules]
[Pages 74702-74847]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2022-24675]

[[Page 74701]]

Vol. 87

Tuesday,

No. 233

December 6, 2022

Part II

Environmental Protection Agency

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40 CFR Part 60

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

  Federal Register / Vol. 87, No. 233 / Tuesday, December 6, 2022 / 
Proposed Rules  

[[Page 74702]]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2021-0317; FRL-8510-04-OAR]
RIN 2060-AV16

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

AGENCY: Environmental Protection Agency (EPA).

ACTION: Supplemental notice of proposed rulemaking.

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SUMMARY: The EPA is issuing this supplemental proposal to update, 
strengthen, and expand the standards proposed on November 15, 2021 
(November 2021 proposal), which are 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 standards for certain sources that were not addressed in the 
November 2021 proposal. Second, the EPA proposes revisions that 
strengthen standards for sources of leaks, provide greater flexibility 
to use innovative advanced detection methods, and establish a super 
emitter response program. Third, the EPA proposes to modify and refine 
certain elements of the proposed standards in response to information 
submitted in public comments on the November 2021 proposal. Finally, 
the EPA proposes details of the timelines and other implementation 
requirements that apply to states to limit methane pollution from 
existing designated facilities in the source category under the Clean 
Air Act (CAA).

DATES: 
    Comments.
    Comments must be received on or before February 13, 2023. Under the 
Paperwork Reduction Act (PRA), OMB is required to make a decision 
concerning the collections of information contained in the proposed 
rule between 30 and 60 days after publication and submission to OMB. A 
comment to OMB is best assured of consideration if the Office of 
Management and Budget (OMB) receives it on or before January 5, 2023.
    Public hearing. The EPA will hold a virtual public hearing on 
January 10, 2023, and January 11, 2023. 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: [email protected]. 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. 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: [email protected] 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; 
fax number: (919) 541-0516; email address: [email protected].

SUPPLEMENTARY INFORMATION: 
    Participation in virtual public hearing. The public hearing will be 
held via virtual platform on January 10, 2023, and January 11, 2023, 
and will convene at 10:00 a.m. Eastern Time (ET) and conclude at 8:00 
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 January 12, 2023. 
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 
[email protected].
    The EPA will begin pre-registering speakers for the hearing no 
later than 1 business day following the 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 [email protected]. The last day to pre-
register to speak at the hearing will be January 5, 2023. 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 4 minutes to provide oral testimony. The 
EPA encourages commenters to provide the EPA with a copy of their oral 
testimony by 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

[[Page 74703]]

such as audio description, please pre-register for the hearing with the 
public hearing team and describe your needs by December 13, 2022. 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 electronically to https://www.regulations.gov/ 
any information that you consider to be CBI or other information whose 
disclosure is restricted by statute. This type of information should be 
submitted 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.
    Submitting CBI. Do not submit information containing CBI to the EPA 
through https://www.regulations.gov/. 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, note the docket ID, 
mark the outside of the digital storage media as CBI and 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 the Instructions section of this document. 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 and 
note the docket ID. 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 Code of Federal Regulations 
(CFR) part 2.
    Our preferred method to receive CBI is for it to be transmitted 
electronically using email attachments, File Transfer Protocol (FTP), 
or other online file sharing services (e.g., Dropbox, OneDrive, Google 
Drive). Electronic submissions must be transmitted directly to the 
OAQPS CBI Office at the email address [email protected], and as 
described in the preceding paragraph, should include clear CBI markings 
and note the docket ID. If assistance is needed with submitting large 
electronic files that exceed the file size limit for email attachments, 
and if you do not have your own file sharing service, please email 
[email protected] to request a file transfer link. If sending CBI 
information through the postal service, please send it 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. The mailed CBI 
material should be double wrapped and clearly marked. Any CBI markings 
should not show through the outer envelope.
    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:

AMEL alternate means of emissions limitation
ANSI American National Standards Institute
APA Administrative Procedures Act
API American Petroleum Institute
ASME American Society of Mechanical Engineers
ASTM American Society for Testing and Materials
AVO audio, visual, and olfactory
AWP alternative work practice
BMP best management practices
boe barrels of oil equivalents
BSER best system of emission reduction
Btu/scf British thermal unit per standard cubic foot
[deg]C degrees Centigrade
CAA Clean Air Act
CBI Confidential Business Information
CCR Code of Colorado Regulations
CDX EPA's Central Data Exchange
CEDRI Compliance and Emissions Data Reporting Interface
CFR Code of Federal Regulations
CH4 methane
CO carbon monoxide
CO2 carbon dioxide
CO2 Eq. carbon dioxide equivalent
CRA Congressional Review Act
CVS closed vent systems
CWA Clean Water Act
D.C. Circuit U.S. Court of Appeals for the District of Columbia 
Circuit
DOE Department of Energy
EAV equivalent annual value
EDF Environmental Defense Fund
EG emission guidelines
EIA U.S. Energy Information Administration
EJ environmental justice
E.O. Executive Order
EPA Environmental Protection Agency
ESD emergency shutdown devices
[deg]F degrees Fahrenheit
FEAST Fugitive Emissions Abatement Simulation Toolkit
FR Federal Register
FRFA final regulatory flexibility analysis
g/hr grams per hour
GHG greenhouse gas
GHGI Inventory of U.S. Greenhouse Gas Emissions and Sinks
GHGRP Greenhouse Gas Reporting Program

[[Page 74704]]

HAP hazardous air pollutant(s)
ICR information collection request
IRFA initial regulatory flexibility analysis
IWG Interagency Working Group on the Social Cost of Greenhouse Gases
kg kilograms
low-e low emission
LDAR leak detection and repair
Mcf thousand cubic feet
METEC Methane Emissions Technology Evaluation Center
MW megawatt
NAAQS National Ambient Air Quality Standards
NAICS North American Industry Classification System
NDE no detectable emissions
NESHAP National Emissions Standards for Hazardous Air Pollutants
NGO non-governmental organization
NHV net heating value
NOX nitrogen oxides
NSPS new source performance standards
NTTAA National Technology Transfer and Advancement Act
OAQPS Office of Air Quality Planning and Standards
OGI optical gas imaging
OMB Office of Management and Budget
PM2.5 particulate matter with a diameter of 2.5 
micrometers or less
ppm parts per million
PRA Paperwork Reduction Act
PTE potential to emit
PV present value
REC reduced emissions completion
RFA Regulatory Flexibility Act
RIA regulatory impact analysis
RULOF remaining useful life and other factors
SBAR Small Business Advocacy Review
SC-CH4 social cost of methane
SC-GHG social cost of greenhouse gases
scf standard cubic feet
scfh standard cubic feet per hour
scfm standard cubic feet per minute
SIP state implementation plan
SO2 sulfur dioxide
SPeCS State Planning Electronic Collaborative System
tpy tons per year
the court U.S. Court of Appeals for the District of Columbia Circuit
TAR Tribal Authority Rule
TIP tribal implementation plan
TSD technical support document
UMRA Unfunded Mandates Reform Act
U.S. United States
VCS Voluntary Consensus Standards
VOC volatile organic compounds
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. Purpose of This Regulatory Action
    A. What is the purpose of this supplemental proposal?
    B. What date defines a new, modified, or reconstructed source 
for purposes of the proposed NSPS OOOOb?
    C. What date defines an existing source for purposes of the 
proposed EG OOOOc?
    D. How will the proposed EG OOOOc impact sources already subject 
to NSPS KKK, NSPS OOOO, or NSPS OOOOa?
    E. How does the EPA consider costs in this supplemental 
proposal?
    F. Legal Basis for Rulemaking Scope
    G. Inflation Reduction Act
IV. Summary and Rationale for Changes to the Proposed NSPS OOOOb and 
EG OOOOc
    A. Fugitive Emissions From Well Sites, Centralized Production 
Facilities, and Compressor Stations
    B. Advanced Methane Detection Technologies
    C. Super-Emitter Response Program
    D. Pneumatic Controllers
    E. Pneumatic Pumps
    F. Wells and Associated Operations
    G. Centrifugal Compressors
    H. Combustion Control Devices
    I. Reciprocating Compressors
    J. Storage Vessels
    K. Covers and Closed Vent Systems
    L. Equipment Leaks at Natural Gas Processing Plants
    M. Sweetening Units
    N. Recordkeeping and Reporting
V. Supplemental Proposal for State, Tribal, and Federal Plan 
Development for Existing Sources
    A. Overview
    B. Establishing Standards of Performance in State Plans
    C. Components of State Plan Submission
    D. Timing of State Plan Submissions and Compliance Times
VI. Use of Optical Gas Imaging in Leak Detection (Appendix K)
    A. Overview of the November 2021 Proposal
    B. Significant Changes Since Proposal
    C. Summary of Proposed Requirements
VII. 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?
VIII. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review and 
Executive Order 13563: Improving Regulation and Regulatory Review
    B. Paperwork Reduction Act (PRA)
    C. Regulatory Flexibility Act (RFA)
    D. Unfunded Mandates Reform Act (UMRA)
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination With 
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children From 
Environmental Health Risks and Safety Risks
    H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use
    I. National Technology Transfer and Advancement Act (NTTAA)
    J. Executive Order 12898: Federal Actions To Address 
Environmental Justice in Minority Populations and Low-Income 
Populations

I. Executive Summary

A. Purpose of the Regulatory Action

    On November 15, 2021, the EPA published a proposed rule (November 
2021 proposal) that was intended to mitigate climate-destabilizing 
pollution and protect human health by reducing greenhouse gas (GHG) and 
VOC emissions from the Oil and Natural Gas Industry,\1\ specifically 
the Crude Oil and Natural Gas source category.\2\ A wide range of 
stakeholders, as well as state and tribal governments, submitted public 
comments on the November 2021 proposal. Over 470,000 public comments 
were submitted. Many commenters representing diverse perspectives 
expressed general support for the proposal and requested that the EPA 
further strengthen the proposed standards and make them more 
comprehensive. Other commenters highlighted implementation or cost 
concerns related to elements of the November 2021 proposal or provided 
specific data and information that the EPA was able to use to refine or 
revise several of the standards included in the November 2021 proposal.
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    \1\ The EPA characterizes the Oil and Natural Gas Industry 
operations as being generally composed of four segments: (1) 
Extraction and production of crude oil and natural gas (``oil and 
natural gas production''), (2) natural gas processing, (3) natural 
gas transmission and storage, and (4) natural gas distribution.
    \2\ The EPA defines the Crude Oil and Natural Gas source 
category to mean: (1) Crude oil production, which includes the well 
and extends to the point of custody transfer to the crude oil 
transmission pipeline or any other forms of transportation; and (2) 
natural gas production, processing, transmission, and storage, which 
include the well and extend to, but do not include, the local 
distribution company custody transfer station, commonly referred to 
as the ``city-gate.''
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    In the November 2021 proposal, the EPA proposed new standards and 
emission guidelines under CAA section 111 which would be included in 40 
CFR part 60 at subpart OOOOb (NSPS OOOOb) and subpart OOOOc (EG OOOOc). 
The purpose of this supplemental proposed rulemaking is to strengthen, 
update, and expand the proposed standards for certain emissions 
sources, including: (1) To reduce emissions from the source category 
more comprehensively by adding proposed standards for certain sources 
that were not addressed in the November 2021 proposal, revising the

[[Page 74705]]

proposed requirements for fugitive emissions monitoring and repair, and 
establishing a super-emitter response program; (2) to encourage the 
deployment of innovative technologies and techniques for detecting and 
reducing methane emissions by providing additional options for the use 
of advanced monitoring; (3) to modify and refine certain elements of 
the proposed standards in response to concerns and information 
identified in an initial review of public comments on the November 2021 
proposal; and (4) to provide additional information not included in the 
November 2021 proposal for public comment, such as the content for the 
new subparts that reflects the proposed standards and emission 
guidelines, and details of the timelines and other requirements that 
apply to states as they develop state plans to implement the emission 
guidelines.
    In the November 2021 proposal, the EPA performed a comprehensive 
analysis of the available data from emission sources in the Crude Oil 
and Natural Gas source category and the latest available information on 
control measures and techniques to identify achievable, cost-effective 
measures to significantly reduce methane and VOC emissions, consistent 
with the requirements of section 111 of the CAA.\3\ This supplemental 
proposal builds on that analysis to apply additional information and 
data provided to the Agency since the November 2021 proposal to 
identify areas to further strengthen standards, such as measures to 
address large emissions events, commonly referred to as super-emitters. 
If finalized and implemented, the proposed actions in this rulemaking, 
as detailed in the November 2021 proposal and this supplemental 
proposal, would lead to significant and cost-effective reductions in 
climate and health-harming pollution and encourage the continued 
development and deployment of innovative technologies to further reduce 
this pollution in the Crude Oil and Natural Gas source category.
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    \3\ 42 U.S.C. 7411.
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    This supplemental proposal comprises distinct actions:
     Update, strengthen, and/or expand on the standards 
proposed in November 2021 under CAA section 111(b) for methane and VOC 
emissions from new, modified, and reconstructed facilities that 
commenced construction, reconstruction, or modification after November 
15, 2021,
     Update, strengthen, and/or expand the presumptive 
standards proposed in November 2021 as part of the CAA section 111(d) 
emission guidelines for methane emissions from existing designated 
facilities that commenced construction, reconstruction, or modification 
on or before November 15, 2021,
     And establish the implementation requirements for states 
to limit methane pollution from existing designated facilities in the 
source category under CAA section 111(d).
    The Oil and Natural Gas Industry is the United States' largest 
industrial emitter of methane, a highly potent GHG.\4\ Methane and VOC 
emissions from the Crude Oil and Natural Gas source category result 
from a variety of industry operations across the supply chain. As 
natural gas moves through the necessarily interconnected system of 
exploration, production, storage, processing, and transmission that 
brings it from wellhead to commerce, emissions primarily result from 
intentional venting, unintentional gas carry-through (e.g., vortexing 
from separator drain, improper liquid level settings, liquid level 
control valve on an upstream separator or scrubber not seating properly 
at the end of an automated liquid dumping event, inefficient separation 
of gas and liquid phases occurring upstream of tanks allowing some gas 
carry-through), routine maintenance, unintentional fugitive emissions, 
flaring, malfunctions, abnormal process conditions, and system upsets. 
These emissions are associated with a range of specific equipment and 
practices, including leaking valves, connectors, and other components 
at well sites and compressor stations; leaks and vented emissions from 
controlled storage vessels; releases from natural gas-driven pneumatic 
pumps and controllers; liquids unloading at well sites; and venting or 
under-performing flaring of associated gas from oil wells. 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 simultaneously reducing multiple pollutants and 
recovering saleable product. These technologies and best practices have 
been deployed by individual oil and natural gas companies, required by 
state regulations, reflected in regulations issued by the EPA and other 
Federal agencies, or utilized by various non-industry groups and 
research teams.
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    \4\ Emissions from EPA (2022) Inventory of U.S. Greenhouse Gas 
Emissions and Sinks: 1990-2020. U.S. Environmental Protection 
Agency, EPA 430-R-22-003. https://www.epa.gov/ghgemissions/draft-inventory-us-greenhouse-gas-emissionsand-sinks-1990-2020.
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    In developing this supplemental proposal, the EPA applied the 
latest available information to refine or supplement the analyses 
presented in the November 2021 proposal. This latest information 
provided additional insights into lessons learned from states' 
regulatory efforts, the emission reduction efforts of leading 
companies, the continued development of new and developing 
technologies, and peer-reviewed research from emission measurement 
campaigns across the United States (U.S.). As stated in the November 
2021 proposal, the EPA solicited comment on all aspects of the proposed 
standards and stated its intent to issue a supplemental proposal that 
revisited and refined certain provisions of that proposal in response 
to information provided by the public. This supplemental proposal does 
just that. For instance, the EPA sought input in the November 2021 
proposal on multiple aspects of the proposed approach for fugitive 
emissions monitoring at well sites, including the baseline emission 
threshold and other criteria (such as the presence of specific types of 
malfunction-prone equipment) that should be used to determine whether a 
well site is required to undertake ongoing fugitive emissions 
monitoring. (86 FR 63115; November 15, 2021). After considering the 
comments and information received, this supplemental proposal includes 
a revised approach for fugitive emissions monitoring at well sites 
utilizing modeling to establish the proposed monitoring frequency and 
detection method for individual sites based on the presence of specific 
types of equipment. In contrast to the November 2021 proposal, this 
supplemental proposal would establish an obligation for all well sites 
to routinely monitor for fugitive emissions and repair leaks found--
ranging from a quarterly audio, visual, and olfactory (AVO) inspection 
for single wellhead-only sites to quarterly optical gas imaging (OGI) 
inspections for any site with significant production equipment. This 
revised approach to addressing fugitive emissions from well sites also 
would carry the monitoring requirements through the entire life of the 
well site and would specify the requirements for ceasing monitoring 
following well closures when production from the entire well site has 
stopped. The EPA is seeking comments about labor requirements to 
implement these monitoring requirements.

[[Page 74706]]

    Super-emitter emissions events \5\ were another key area in the 
November 2021 proposal for which the EPA solicited comment. (86 FR 
63177; November 15, 2021). This supplemental proposal includes various 
standards that, when implemented by an owner or operator, could reduce 
or eliminate the occurrence of super-emitter emissions events, such as 
the inclusion of specific compliance assurance measures to ensure that 
flares are operating as designed with a continuously lit pilot. In 
addition, this supplemental notice proposes a super-emitter response 
program to trigger swift mitigation of super-emitter emissions events 
when they are identified through credible information provided by 
regulatory authorities or approved qualified third-party sources.
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    \5\ In the November 2021 proposal, the EPA solicited comment on 
the use of information collected by communities and others to 
address large emissions events, which this supplemental proposal now 
defines as ``super-emitter emissions events.''
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    Content for the new subparts reflecting these proposed changes is 
available in the docket for this action (Docket ID No. EPA-HQ-OAR-2021-
0317) and supplements the redline versions of NSPS OOOO and NSPS OOOOa 
provided in the November 2021 proposal (Docket ID Nos. EPA-HQ-OAR-2021-
0317-0095 and EPA-HQ-OAR-2021-0317-0097). In addition, the EPA is 
providing an updated regulatory impact analysis (RIA) that seeks to 
account for the full impacts of these proposed actions.
    Additionally, the EPA is seeking comment and information on the 
proposed provisions for the use of advanced methane measurement 
technologies for both periodic screening and continuous monitoring as 
an alternative to OGI. The revised proposal includes a matrix that 
provides various monitoring frequencies based on specific performance 
criteria a technology would need to meet in order to be used for 
periodic screening. In addition to this proposed matrix, this 
supplemental proposal includes provisions for requesting the use of 
alternative test method(s) that, where approved, could be used broadly 
for deploying these alternative technologies. Further, the EPA is 
proposing a framework for the use of continuous monitoring systems that 
provide a mass emissions rate with site-specific action levels based on 
changes in quarterly average emissions and on the detection of an acute 
large emission spike or event on a shorter term. Diverse stakeholders 
expressed strong interest in employing these new tools for methane 
identification and quantification, particularly for super-emitters, and 
in the EPA's creation of a regime to promote and accommodate their 
development and use. This proposal provides an approach for fostering 
those alternatives, which could provide a template for future 
innovation-conducive regulatory standards. The EPA is also seeking 
comment on the detection limits of all monitoring and inspection 
requirements.
    Throughout this action, unless noted otherwise, the EPA is 
requesting comments on all aspects of the supplemental proposal to 
enable the EPA to develop a final rule that, consistent with our 
responsibilities under section 111 of the CAA, achieves the greatest 
possible reductions in methane and VOC emissions while remaining 
achievable, cost effective, and conducive to technological innovation. 
Because this preamble includes comment solicitations/requests on 
several topics and issues, we have prepared a separate memorandum that 
presents these comment requests by section and topic as a guide to 
assist commenters in preparing comments. This memorandum can be 
obtained from the Docket for this action (see Docket ID No. EPA-HQ-OAR-
2021-0317). The title of the memorandum is ``Standards of Performance 
for New, Reconstructed, and Modified Sources and Emissions Guidelines 
for Existing Sources: Oil and Natural Gas Sector Climate Review--
Supplemental Proposed Rule Summary of Comment Solicitations.'' It is 
not necessary to resubmit comments that were submitted for the November 
2021 proposal.

B. Summary of the Major Provisions of the Regulatory Action

    This supplemental proposal includes two distinct rulemaking actions 
under the CAA. First, the EPA is proposing specific changes to 
strengthen the proposed requirements under CAA section 111(b) for 
methane and VOC emissions from sources that commenced construction, 
modification, or reconstruction after November 15, 2021. These proposed 
revisions to strengthen the November 15, 2021, proposed standards of 
performance will be in a new subpart, NSPS OOOOb, and include proposed 
standards for emission sources previously not regulated for this source 
category.
    Second, pursuant to CAA section 111(d), the EPA is proposing 
specific revisions to strengthen the first nationwide emission 
guideline (EG) for states to limit methane pollution from existing 
designated facilities in the Crude Oil and Natural Gas source category. 
The proposed revisions to strengthen the November 15, 2021, proposed 
presumptive standards will be in a new subpart, EG OOOOc. The emissions 
guidelines (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 (in the form of limitations 
on methane) from their designated facilities in the Crude Oil and 
Natural Gas source category.
    As CAA section 111(a)(1) requires, the standards of performance 
under section 111(b) and presumptive standards under section 111(d) 
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.'' \6\ In this proposed 
supplemental rulemaking, we evaluated new data made available to the 
EPA and information provided from public comments on the November 2021 
proposal to update the analyses and evaluate whether revisions to the 
proposed BSER should be considered. For any potential control measure 
evaluated in this action, as in the November 2021 proposal, the EPA 
evaluated the emission reductions achievable through these measures and 
employed multiple approaches to evaluate the reasonableness of control 
costs associated with the options under consideration. For example, in 
evaluating controls for reducing VOC and methane emissions from new 
sources, we considered a control measure's cost-effectiveness under 
both a ``single pollutant cost-effectiveness'' approach and a 
``multipollutant cost-effectiveness'' approach, to appropriately 
reflect that the systems of emission reduction evaluated in this rule 
typically achieve reductions in multiple pollutants simultaneously and 
secure a multiplicity of climate and public health benefits. We also

[[Page 74707]]

compared: (1) The capital costs that would be incurred through 
compliance with the proposed standards against the industry's current 
level of capital expenditures and (2) the annualized costs against the 
industry's estimated annual revenues. For a detailed discussion of the 
EPA's consideration of this and other BSER statutory elements, please 
see section III.E of this preamble, 86 FR 63133; November 15, 2021, and 
86 FR 63153; November 15, 2021. Table 1 summarizes the applicability 
dates for the four subparts that the EPA's November 2021 proposal 
included.
---------------------------------------------------------------------------

    \6\ The EPA notes that design, equipment, work practice or 
operational standards established under CAA section 111(h) (commonly 
referred to as ``work practice standards'') reflect the ``best 
technological system of continuous emission reduction'' and that 
this phrasing differs from the ``best system of emission reduction'' 
phrase in the definition of ``standard of performance'' in CAA 
section 111(a)(1). Although the differences in these phrases may be 
meaningful in other contexts, for purposes of evaluating the sources 
and systems of emission reduction at issue in this rulemaking, the 
EPA has applied these concepts in an essentially comparable manner 
because the systems of emission reduction the EPA evaluated are all 
technological.

    Table 1--Applicable Dates for Proposed Subparts Addressed in This
                             Proposed Action
------------------------------------------------------------------------
             Subpart                  Source type      Applicable dates
------------------------------------------------------------------------
40 CFR part 60, subpart OOOO....  New, modified, or   After August 23,
                                   reconstructed       2011, and on or
                                   sources.            before September
                                                       18, 2015.
40 CFR part 60, subpart OOOOa...  New, modified, or   After September
                                   reconstructed       18, 2015, and on
                                   sources.            or before
                                                       November 15,
                                                       2021.
40 CFR part 60, subpart OOOOb...  New, modified, or   After November 15,
                                   reconstructed       2021.\1\
                                   sources.
40 CFR part 60, subpart OOOOc...  Existing sources..  On or before
                                                       November 15,
                                                       2021.\2\
------------------------------------------------------------------------
\1\ The standards for dry seal centrifugal compressors will apply to
  those for which construction, reconstruction, or modification
  commenced after December 6, 2022.
\2\ The presumptive standards for dry seal centrifugal compressors will
  apply to those for which construction, reconstruction, or modification
  commenced on or before December 6, 2022.

1. Proposed Standards for New, Modified and Reconstructed Sources After 
November 15, 2021 (Proposed NSPS OOOOb)
    As described in section IV of this preamble, the EPA is proposing 
several changes to the BSER and the standards for certain affected 
facilities based on a review of new data made available to the EPA and 
information provided in public comments. For the other standards 
proposed in the November 2021 proposal that generally remain unchanged 
in this action, we have provided further justifications or 
clarifications as needed based on the public comments and other 
additional information received, as described in section IV of this 
preamble. The proposed NSPS would apply to new, modified, and 
reconstructed emission sources across the Crude Oil and Natural Gas 
source category, including the production, processing, transmission, 
and storage segments, for which construction, reconstruction, or 
modification commenced after November 15, 2021, which is the date of 
publication of the proposed NSPS OOOOb. In addition, the EPA is 
proposing methane and VOC standards for one new emission source that is 
currently unregulated (i.e., dry seal centrifugal compressors). Because 
standards for dry seal centrifugal compressors were not proposed in the 
November 2021 proposal, new, modified, and reconstructed dry seal 
centrifugal compressors are defined as those for which construction, 
reconstruction, or modification commenced after December 6, 2022.
    In particular, this action proposes revisions to strengthen the 
proposed VOC and methane standards addressing fugitive emissions from 
well sites and pneumatic pumps; generally leaves unchanged the proposed 
sulfur dioxide (SO2) performance standard for sweetening 
units and the proposed VOC and methane performance standards for well 
completions, gas well liquids unloading operations, associated gas from 
oil wells, wet seal centrifugal compressors, reciprocating compressors, 
pneumatic controllers, storage vessels, fugitive emissions from 
compressor stations, and equipment leaks at natural gas processing 
plants; and proposes new VOC and methane standards for dry seal 
centrifugal compressors previously not regulated. A summary of the 
proposed BSER determination and proposed NSPS for new, modified, and 
reconstructed sources (NSPS OOOOb) is presented in Table 2. See section 
IV of this preamble for a complete discussion of the proposed changes 
to the BSER determination and proposed NSPS requirements.
    This proposal also includes provisions for the use of alternative 
test methods using advanced methane detection technologies that allow 
for periodic screening or continuous monitoring for fugitive emissions 
and emissions from covers and closed vent systems (CVS) used to route 
emissions to control devices. These proposed alternatives would allow 
for advanced screening technologies, which could be used to identify 
large emissions or ``super-emitter emissions events'' sooner than the 
proposed use of periodic OGI monitoring for fugitive emissions, covers 
on storage vessels, and CVS. Various studies using aerial monitoring 
techniques have identified large emissions from these types of sources. 
Finally, in order to ensure that super-emitter emissions events are 
identified and mitigated as quickly as possible, the EPA is proposing a 
super-emitter response program where an owner or operator must 
investigate and take appropriate mitigation actions upon receiving 
certified notifications of detected emissions that are 100 kg/hr of 
methane or greater. See sections IV.A and IV.B of this preamble for a 
complete discussion of these proposed provisions.
2. Proposed EG for Sources Constructed Prior to November 15, 2021 
(Proposed EG OOOOc)
    As described in sections IV and V of this preamble, the EPA is 
proposing several changes to the BSER determinations and presumptive 
standards that were proposed under the authority of CAA section 111(d) 
in the November 2021 proposal. These changes are based on a review of 
new data made available to the EPA and information provided in public 
comments. In the November 2021 proposal the EPA proposed the first 
nationwide EG for GHG (in the form of methane limitations) for the 
Crude Oil and Natural Gas source category, including the production, 
processing, transmission, and storage segments (EG OOOOc).
    This action proposes revisions to strengthen the proposed 
presumptive standards for methane addressing fugitive emissions from 
well sites, pneumatic controllers, pneumatic pumps, and wet seal 
centrifugal compressors; generally leaves unchanged the proposed 
methane presumptive standards for associated gas from oil wells, 
reciprocating compressors, storage vessels, fugitive emissions from 
compressor stations, and equipment leaks at natural gas processing 
plants; and proposes new methane presumptive standards for well liquids 
unloading operations and dry seal centrifugal compressors previously

[[Page 74708]]

not proposed to be regulated. A summary of the proposed BSER 
determination and proposed presumptive standards for EG OOOOc is 
presented in Table 3. See section IV of this preamble for a complete 
discussion of the proposed changes to the BSER determination and 
proposed presumptive standards.
    This proposal also includes the same provisions described for NSPS 
OOOOb that allow for the use of alternative test methods using advanced 
methane detection technologies for periodic screening or continuous 
monitoring for fugitive emissions and emissions from covers and CVS 
used to route emissions to control devices. Finally, the EPA is also 
proposing a super-emitter response program, where an owner or operator 
that receives certified notifications of detected emissions that are 
100 kg/hr or greater is obligated to take action to address those 
emissions. See sections IV.A and IV.B of this preamble for a complete 
discussion of these proposed provisions.
    As stated in the November 2021 proposal,\7\ when the EPA 
establishes NSPS for a source category, the EPA is required to issue EG 
to reduce emissions of certain pollutants from existing sources in that 
same source category. In such circumstances, under CAA section 111(d), 
the EPA must issue regulations to establish procedures under which 
states submit plans to establish, implement, and enforce standards of 
performance for existing sources for certain air pollutants to which a 
Federal NSPS would apply if such existing source were a new source. 
Thus, the issuance of CAA section 111(d) final EG does not impose 
binding requirements directly on sources but instead provides 
requirements for states in developing their plans. Although state plans 
bear the obligation to establish standards of performance, under CAA 
sections 111(a)(1) and 111(d), those standards of performance must 
reflect the degree of emission limitation achievable through the 
application of the BSER as determined by the Administrator. As provided 
in CAA section 111(d), a state may choose to take into account 
remaining useful life and other factors in applying a standard of 
performance to a particular source, consistent with the CAA, the EPA's 
implementing regulations, and the final EG.
---------------------------------------------------------------------------

    \7\ See 86 FR 63117 (November 15, 2021).
---------------------------------------------------------------------------

    In this supplemental proposal, the EPA is proposing changes to the 
BSER determinations and the degree of limitation achievable through 
application of the BSER for certain existing equipment, processes, and 
activities across the Crude Oil and Natural Gas source category. Those 
changes are discussed in section IV of this preamble. Section V of this 
preamble discusses the components of EG, including the steps, 
requirements, and considerations associated with the development, 
submittal, and implementation of state, tribal, and Federal plans, as 
appropriate. For the EG, the EPA is proposing to translate the degree 
of emission limitation achievable through application of the BSER 
(i.e., level of stringency) into presumptive standards that states may 
use in the development of state plans for specific designated 
facilities. By doing this, the EPA has formatted the proposed EG such 
that if a state chooses to adopt these presumptive standards, once 
finalized, as the standards of performance in a state plan, the EPA 
could approve such a plan as meeting the requirements of CAA section 
111(d) and the finalized EG, if the plan meets all other applicable 
requirements. In this way, the presumptive standards included in the EG 
serve a function similar to that of a model rule,\8\ because they are 
intended to assist states in developing their plan submissions by 
providing states with a starting point for standards that are based on 
general industry parameters and assumptions. The EPA anticipates that 
providing these presumptive standards will create a streamlined 
approach for states in developing plans and the EPA in evaluating state 
plans. However, the EPA's action on each state plan submission is 
carried out via rulemaking, which includes public notice and comment. 
Inclusion of presumptive standards in the EG does not seek to pre-
determine the outcomes of any future rulemaking.
---------------------------------------------------------------------------

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

    Designated facilities located in Indian country would not be 
encompassed within a state's CAA section 111(d) plan. Instead, an 
eligible tribe that has one or more designated facilities located in 
its area of Indian country would have the opportunity, but not the 
obligation, to seek authority and submit a plan that establishes 
standards of performance for those facilities on its Tribal lands. If a 
tribe does not submit a plan, or if the EPA does not approve a tribe's 
plan, then the EPA has the authority to establish a Federal plan for 
that tribe. A summary of the proposed EG for existing sources (EG 
OOOOc) for the oil and natural gas sector is presented in Table 3. See 
sections IV and V of this preamble for a complete discussion of the 
proposed EG requirements.

 Table 2--Summary of Proposed BSER and Proposed Standards of Performance
                            for GHGs and VOCs
                              [NSPS OOOOb]
------------------------------------------------------------------------
                                                     Proposed standards
       Affected source            Proposed BSER      of performance  for
                                                        GHGs and VOCs
------------------------------------------------------------------------
Super-Emitters..............  Root cause analysis   Root cause analysis
                               and corrective        and corrective
                               action following      action following
                               notification of       notification of
                               super-emitter         super-emitter
                               emissions event.      emissions event.
Fugitive Emissions: Single    Quarterly AVO         Quarterly AVO
 Wellhead Only Well Sites      inspections.          inspections. Repair
 and Small Well Sites.                               for indications of
                                                     potential leaks
                                                     within 15 days of
                                                     inspection.
                                                    Fugitive monitoring
                                                     continues for all
                                                     well sites until
                                                     the site has been
                                                     closed, including
                                                     plugging the wells
                                                     at the site and
                                                     submitting a well
                                                     closure report.
Fugitive Emissions: Multi-    Quarterly AVO         Quarterly AVO
 wellhead Only Well Sites (2   inspections.          inspections. Repair
 or more wellheads).          AND.................   for indications of
                                                     potential leaks
                                                     within 15 days of
                                                     inspection.

[[Page 74709]]

 
                              Monitoring and        Semiannual OGI
                               repair based on       monitoring
                               semiannual            (Optional
                               monitoring using      semiannual EPA
                               OGI \2\.              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 monitoring
                                                     continues for all
                                                     well sites until
                                                     the site has been
                                                     closed, including
                                                     plugging the wells
                                                     at the site and
                                                     submitting a well
                                                     closure report.
Fugitive Emissions: Well      Bimonthly AVO         Bimonthly AVO
 Sites with Major Production   monitoring (i.e.,     inspections. Repair
 and Processing Equipment      every other month).   for indications of
 and Centralized Production   AND.................   potential leaks
 Facilities.                  Well sites with        within 15 days of
                               specified major       inspection.
                               production and       AND
                               processing           Well sites with
                               equipment:            specified major
                               Monitoring and        production and
                               repair based on       processing
                               quarterly             equipment:
                               monitoring using      Quarterly OGI
                               OGI.                  monitoring.
                                                     (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 monitoring
                                                     continues for all
                                                     well sites until
                                                     the site has been
                                                     closed, including
                                                     plugging the wells
                                                     at the site and
                                                     submitting a well
                                                     closure report.
Fugitive Emissions:           Monthly AVO           Monthly AVO
 Compressor Stations.          monitoring.           monitoring.
                              AND.................  AND
                              Monitoring and        Quarterly OGI
                               repair based on       monitoring.
                               quarterly             (Optional quarterly
                               monitoring using      EPA Method 21
                               OGI.                  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      Monitoring and        Annual OGI
 Sites and Compressor          repair based on       monitoring.
 Stations on Alaska North      annual monitoring     (Optional annual
 Slope.                        using OGI.            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      (Optional)            (Optional)
 Sites and Compressor          Screening,            Alternative
 Stations.                     monitoring, and       periodic screening
                               repair based on       with advanced
                               periodic screening    measurement
                               using an advanced     technology instead
                               measurement           of OGI and AVO
                               technology instead    monitoring
                               of OGI monitoring.    according to
                                                     minimum detection
                                                     sensitivity of
                                                     technology.
Fugitive Emissions: Well      (Optional)            (Optional)
 Sites and Compressor          Monitoring and        Alternative
 Stations.                     repair based on       continuous
                               using a continuous    monitoring system
                               monitoring system     instead of OGI and
                               instead of OGI        AVO monitoring.
                               monitoring.
Storage Vessels: A Single     Capture and route to  95 percent reduction
 Storage Vessel or Tank        a control device.     of VOC and methane.
 Battery with PTE \4\ of 6
 tpy or more of VOC and PTE
 of 20 tpy or more of
 methane.
Pneumatic Controllers:        Use of zero-          VOC and methane
 Natural gas-driven that       emissions             emission rate of
 Vent to the Atmosphere.       controllers.          zero.
Pneumatic Controllers:        Use of low-bleed      Natural gas bleed
 Alaska (at sites where        pneumatic             rate no greater
 onsite power is not           controllers.          than 6 scfh.\5\
 available--continuous bleed
 natural gas-driven).
Pneumatic Controllers:        Monitor and repair    OGI monitoring and
 Alaska (at sites where        through fugitive      repair of emissions
 onsite power is not           emissions program.    from controller
 available--intermittent                             malfunctions.
 natural gas-driven).
Well Liquids Unloading......  Employ techniques or  Perform liquids
                               technologies that     unloading with zero
                               eliminate methane     methane or VOC
                               and VOC emissions.    emissions. If this
                               If this is not        is not feasible for
                               feasible for safety   safety or technical
                               or technical          reasons, employ
                               reasons, employ       best management
                               best management       practices to
                               practices to          minimize venting of
                               minimize venting of   emissions to the
                               emissions to the      maximum extent
                               maximum extent        possible.
                               possible.
Wet Seal Centrifugal          Capture and route     95 percent reduction
 Compressors (except for       emissions from the    of methane and VOC
 those located at well         wet seal fluid        emissions.
 sites).                       degassing system to
                               a control device.
Dry Seal Centrifugal          Conduct preventative  Volumetric flow rate
 Compressors (except for       maintenance and       of 3 scfm.
 those located at well         repair to maintain
 sites).                       flow rate at or
                               below 3 scfm \7\.

[[Page 74710]]

 
Reciprocating Compressors     Repair or replace     Volumetric flow rate
 (except for those located     the reciprocating     of 2 scfm.
 at well sites).               compressor rod
                               packing in order to
                               maintain a flow
                               rate at or below 2
                               scfm.
Pneumatic Pumps.............  Use of zero-emission  Methane and VOC
                               pumps that are not    emission rate of
                               powered by natural    zero.
                               gas.
Well Completions:             Combination of REC    Applies to each well
 Subcategory 1 (non-wildcat    \8\ and the use of    completion
 and non-delineation wells).   a completion          operation with
                               combustion device.    hydraulic
                                                     fracturing.
                                                    REC in combination
                                                     with a completion
                                                     combustion device;
                                                     venting in lieu of
                                                     combustion where
                                                     combustion would
                                                     present
                                                     demonstrable 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,
                                                     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:             Use of a completion   Applies to each well
 Subcategory 2 (exploratory,   combustion device.    completion
 wildcat, and delineation                            operation with
 wells and low-pressure                              hydraulic
 wells).                                             fracturing.
                                                    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    LDAR \9\ with         LDAR with OGI
 Gas Processing Plants.        bimonthly OGI.        following
                                                     procedures in
                                                     appendix K.
Oil Wells with Associated     Route associated gas  Route associated gas
 Gas.                          to a sales line. If   to a sales line. If
                               access to a sales     access to a sales
                               line is not           line is not
                               available, the gas    available, the gas
                               can be used as an     can be used as an
                               onsite fuel source,   onsite fuel source
                               used for another      or used for another
                               useful purpose that   useful purpose that
                               a purchased fuel or   a purchased fuel or
                               raw material would    raw material would
                               serve, or routed to   serve. If
                               a flare or other      demonstrated that a
                               control device that   sales line and
                               achieves at least     beneficial uses are
                               95 percent            not technically
                               reduction in          feasible, the gas
                               methane and VOC       can be routed to a
                               emissions.            flare or other
                                                     control device that
                                                     achieves at least
                                                     95 percent
                                                     reduction in
                                                     methane and VOC
                                                     emissions.
Sweetening Units............  Achieve SO2 emission  Achieve required
                               reduction             minimum SO2
                               efficiency.           emission reduction
                                                     efficiency.
------------------------------------------------------------------------
\1\ tpy (tons per year).
\2\ OGI (optical gas imaging).
\3\ ppm (parts per million).
\4\ PTE (potential to emit).

[[Page 74711]]

 
\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)
------------------------------------------------------------------------
                                                    Proposed presumptive
     Designated facility          Proposed BSER      standards for GHGs
------------------------------------------------------------------------
Super-Emitters..............  Root cause analysis   Root cause analysis
                               and corrective        and corrective
                               action following      action following
                               notification of       notification by an
                               super-emitter         EPA-approved entity
                               emissions event.      or regulatory
                                                     authority of a
                                                     super-emitter
                                                     emissions event.\9\
Fugitive Emissions: Single    Quarterly AVO         Quarterly AVO
 Wellhead Only Well Sites      inspections.          inspections. Repair
 and Small Well Sites.                               for indications of
                                                     potential leaks
                                                     within 15 days of
                                                     inspection.
                                                    Fugitive monitoring
                                                     continues for all
                                                     well sites until
                                                     the site has been
                                                     closed, including
                                                     plugging the wells
                                                     at the site and
                                                     submitting a well
                                                     closure report.
Fugitive Emissions: Multi-    Quarterly AVO         Quarterly AVO
 wellhead Only Well Sites (2   inspections.          inspections. Repair
 or more wellheads).          AND.................   for indications of
                              Monitoring and         potential leaks
                               repair based on       within 15 days of
                               semiannual            inspection.
                               monitoring using     Semiannual OGI
                               OGI \2\.              monitoring
                                                     (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 monitoring
                                                     continues for all
                                                     well sites until
                                                     the site has been
                                                     closed, including
                                                     plugging the wells
                                                     at the site and
                                                     submitting a well
                                                     closure report.
Fugitive Emissions: Well      Bimonthly AVO         Bimonthly AVO
 Sites and Centralized         monitoring (i.e.,     inspections. Repair
 Production Facilities.        every other month).   for indications of
                              AND.................   potential leaks
                              Well sites with        within 15 days of
                               specified major       inspection.
                               production and       AND
                               processing           Well sites with
                               equipment:            specified major
                               Monitoring and        production and
                               repair based on       processing
                               quarterly             equipment:
                               monitoring using      Quarterly OGI
                               OGI.                  monitoring.
                                                     (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 monitoring
                                                     continues for all
                                                     well sites until
                                                     the site has been
                                                     closed, including
                                                     plugging the wells
                                                     at the site and
                                                     submitting a well
                                                     closure report.
Fugitive Emissions:           Monthly AVO           Monthly AVO
 Compressor Stations.          monitoring.           monitoring.
                              AND.................  AND
                              Monitoring and        Quarterly OGI
                               repair based on       monitoring.
                               quarterly             (Optional quarterly
                               monitoring using      EPA Method 21
                               OGI.                  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      Monitoring and        Annual OGI
 Sites and Compressor          repair based on       monitoring.
 Stations on Alaska North      annual monitoring     (Optional annual
 Slope.                        using OGI.            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      (Optional)            (Optional)
 Sites and Compressor          Screening,            Alternative
 Stations.                     monitoring, and       periodic screening
                               repair based on       with advanced
                               periodic screening    measurement
                               using an advanced     technology instead
                               measurement           of OGI monitoring.
                               technology instead
                               of OGI monitoring.
Fugitive Emissions: Well      (Optional)            (Optional)
 Sites and Compressor          Monitoring and        Alternative
 Stations.                     repair based on       continuous
                               using a continuous    monitoring system
                               monitoring system     instead of OGI
                               instead of OGI        monitoring.
                               monitoring.
Storage Vessels: Tank         Capture and route to  95 percent reduction
 Battery with PTE of 20 tpy    a control device.     of methane.
 or More of Methane.
Pneumatic Controllers:        Use of zero-          Methane emission
 Natural gas-driven that       emissions             rate of zero.
 Vent to the Atmosphere.       controllers.

[[Page 74712]]

 
Pneumatic Controllers:        Use of low-bleed      Natural gas bleed
 Alaska (at sites where        pneumatic             rate no greater
 onsite power is not           controllers.          than 6 scfh.
 available--continuous bleed
 natural gas-driven).
Pneumatic Controllers:        Monitor and repair    OGI monitoring and
 Alaska (at sites where        through fugitive      repair of emissions
 onsite power is not           emissions program.    from controller
 available--intermittent                             malfunctions.
 natural gas-driven).
Gas Well Liquids Unloading..  Employ techniques or  Perform liquids
                               technologies that     unloading with zero
                               eliminate methane     methane emissions.
                               emissions. If this    If this is not
                               is not feasible for   feasible for safety
                               safety or technical   or technical
                               reasons, employ       reasons, employ
                               best management       best management
                               practices to          practices to
                               minimize venting of   minimize venting of
                               emissions to the      emissions to the
                               maximum extent        maximum extent
                               possible.             possible.
Wet Seal Centrifugal          Conduct preventative  Volumetric flow rate
 Compressors (except for       maintenance and       of 3 scfm.
 those located at well         repair to maintain
 sites).                       flow rate at or
                               below 3 scfm \7\.
Dry Seal Centrifugal          Conduct preventative  Volumetric flow rate
 Compressors (except for       maintenance and       of 3 scfm.
 those located at well         repair to maintain
 sites).                       flow rate at or
                               below 3 scfm \7\.
Reciprocating Compressors     Repair or replace     Volumetric flow rate
 (except for those located     the reciprocating     of 2 scfm.
 at well sites).               compressor rod
                               packing in order to
                               maintain a flow
                               rate at or below 2
                               scfm.
Pneumatic Pumps.............  Use of zero-emission  Methane emission
                               pumps that are not    rate of zero.
                               powered by natural
                               gas.
Equipment Leaks at Natural    LDAR with bimonthly   LDAR with OGI
 Gas Processing Plants.        OGI.                  following
                                                     procedures in
                                                     appendix K.
Oil Wells with Associated     Route associated gas  Route associated gas
 Gas.                          to a sales line. If   to a sales line. If
                               access to a sales     access to a sales
                               line is not           line is not
                               available, the gas    available, the gas
                               can be used as an     can be used as an
                               onsite fuel source,   onsite fuel source
                               used for another      or used for another
                               useful purpose that   useful purpose that
                               a purchased fuel or   a purchased fuel or
                               raw material would    raw material would
                               serve, or routed to   serve. If
                               a flare or other      demonstrated that a
                               control device that   sales line and
                               achieves at least     beneficial uses are
                               95 percent            not technically
                               reduction in          feasible, the gas
                               methane emissions.    can be routed to a
                                                     flare or other
                                                     control device that
                                                     achieves at least
                                                     95 percent
                                                     reduction in
                                                     methane emissions.
------------------------------------------------------------------------

C. Costs and Benefits

    In accordance with the requirements of Executive Order (E.O.) 
12866, the EPA projected the emissions reductions, costs, and benefits 
that may result from this proposed action if finalized as proposed. 
These results are presented in detail in the RIA accompanying this 
proposal developed in response to E.O. 12866. The RIA focuses on the 
elements of the proposed rule that are likely to result in quantifiable 
cost or emissions changes compared to a baseline that incorporates 
changes to the regulatory requirements induced by the Congressional 
Review Act (CRA) resolution \10\ but does not incorporate the proposed 
standards. 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.
---------------------------------------------------------------------------

    \9\ As described in section IV.C, the EPA is proposing a super-
emitter response program under the statutory rationale that super-
emitters are a designated facility. The EPA is also proposing the 
program under a second rationale that the super-emitter response 
program constitutes work practice standards for certain sources and 
compliance assurance measures for other sources. Under either 
rationale, state plans are generally required to adopt the super-
emitter response program either as presumptive standards or as 
measures that provide for the implementation and enforcement of such 
standards.
    \10\ See November 2021 Proposal, 86 FR at 63116 (discussing the 
CRA Resolution and its effect on regulatory requirements).
---------------------------------------------------------------------------

    The initial analysis year in the RIA is 2023 as we assume the 
proposed rule will be finalized early in 2023. The NSPS will take 
effect immediately and impact sources constructed after publication of 
the proposed rule. The EG will take longer to go into effect as states 
will need to develop implementation plans in response to the rule and 
have them approved by the EPA. We assume in the RIA that this process 
will take 3 years, and so EG impacts will begin in 2026. The final 
analysis year is 2035, which allows us to provide 10 years of projected 
impacts after the EG is assumed to take effect.
    The cost analysis presented in the RIA reflects a nationwide 
engineering analysis of compliance cost and emissions reductions, of 
which there are two main components. The first component is a set of 
representative or model plants for each regulated facility, segment, 
and control option. The characteristics of the model plant include 
typical equipment, operating characteristics, and representative 
factors including baseline emissions and the costs, emissions 
reductions, and product recovery resulting from each control option. 
The second component is a set of projections of activity data for 
affected facilities, distinguished by vintage, year, and other 
necessary attributes (e.g., oil versus natural gas wells). Impacts are 
calculated by setting parameters on how and when affected facilities 
are assumed to respond to a particular regulatory regime, multiplying 
activity data by model plant cost and emissions estimates, differencing 
from the baseline scenario, and then summing to the desired level of 
aggregation. In addition to emissions reductions, some control options 
result in natural gas recovery, which can then be combusted in 
production or sold. Where applicable, we present projected compliance 
costs with and without the projected revenues from product recovery.
    The EPA expects climate and health benefits due to the emissions 
reductions projected under this proposed rule. The EPA estimated the 
climate benefits of

[[Page 74713]]

methane (CH4) emission reductions expected from this 
proposed rule using the social cost of methane (SC-CH4) 
estimates presented in the ``Technical Support Document: Social Cost of 
Carbon, Methane, and Nitrous Oxide Interim Estimates under E.O. 13990'' 
(IWG 2021) published in February 2021 by the Interagency Working Group 
on the Social Cost of Greenhouse Gases (IWG). As a member of the IWG 
involved in the development of the February 2021 TSD, the EPA agrees 
that these estimates continue to represent at this time the most 
appropriate estimate of the SC-CH4 until revised estimates 
have been developed reflecting the latest, peer-reviewed science. 
However, as discussed in Section VII.E, the EPA also presents a 
sensitivity analysis of the monetized climate benefits using a set of 
SC-CH4 estimates that incorporates recent research 
addressing recommendations of the National Academies of Sciences, 
Engineering, and Medicine (2017). The EPA notes that the benefits 
analysis is entirely distinct from the statutory BSER determinations 
proposed herein and is presented solely for the purposes of complying 
with E.O. 12866.
    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, particulate matter with 
a diameter of 2.5 micrometers or less (PM2.5), and hazardous 
air pollutants (HAP). Calculating ozone impacts from VOC emissions 
changes requires information about the spatial patterns in those 
emissions changes. In addition, the ozone health effects from the 
proposed rule will depend on the relative proximity of expected VOC and 
ozone changes to population. In this analysis, we have not 
characterized VOC emissions changes at a finer spatial resolution than 
the national total. In light of these uncertainties, we present an 
illustrative screening analysis in appendix C of the RIA based on 
modeled oil and natural gas VOC contributions to ozone concentrations 
as they occurred in 2017 and do not include the results of this 
analysis in the estimate of benefits and net benefits projected from 
this proposal.
    The projected national-level emissions reductions over the 2023 to 
2035 period anticipated under the proposed requirements are presented 
in Table 4. Table 5 presents the PV and EAV of the projected benefits, 
costs, and net benefits over the 2023 to 2035 period under the proposed 
requirements using discount rates of 3 and 7 percent. The estimates 
presented in Tables 4 and 5 reflect an updated analysis compared with 
the RIA that accompanied the November 2021 proposal. The updated 
analysis not only incorporates the new provisions put forth in the 
supplemental proposal (in addition to the elements of the November 2021 
proposal that are unchanged), but also includes key updates to 
assumptions and methodologies that impact both the baseline and policy 
scenarios. As such, the estimates presented in the tables are not 
directly comparable to corresponding estimates presented in the 
November 2021 proposal. Additionally, we note that the estimated 
emission reductions in both proposals may not fully characterize the 
emissions reductions achieved by this rule because they might not fully 
account for the emissions resulting from super-emitter emissions events 
that would be prevented or quickly corrected as a result of this rule.
    The EPA solicits comments on any relevant data, appropriate 
methodologies, or reliable estimates to help quantify the costs, 
emissions reductions, benefits, and potential distributional effects 
related to super-emitter events, the proposed emissions control 
requirements for associated gas from oil wells, and the proposed 
storage vessel control requirements at centralized production 
facilities and in the gathering and boosting segment.

 Table 4--Projected Emissions Reductions Under the Proposed Rule, 2023-
                               2035 Total
------------------------------------------------------------------------
                                                    Emissions reductions
                     Pollutant                        (2023-2035 total)
------------------------------------------------------------------------
Methane (million short tons) \a\..................                    36
VOC (million short tons)..........................                   9.7
Hazardous Air Pollutant (million short tons)......                  0.39
Methane (million metric tons CO2 Eq.) \b\.........                   810
------------------------------------------------------------------------
\a\ To convert from short tons to metric tons, multiply the short tons
  by 0.907. Alternatively, to convert metric tons to short tons,
  multiply metric tons by 1.102.
\b\ Carbon dioxide equivalent (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 millions of 2019 dollars] \a\
----------------------------------------------------------------------------------------------------------------
                                                       Equivalent annual                       Equivalent annual
                                    Present value            value           Present value           value
----------------------------------------------------------------------------------------------------------------
                                                             3 Percent Discount Rate
                                --------------------------------------------------------------------------------
Climate Benefits \b\...........        $48,000              $4,500              $48,000             $4,500
----------------------------------------------------------------------------------------------------------------
                                         3 Percent Discount Rate
                                         7 Percent Discount Rate
                                --------------------------------------------------------------------------------
Net Compliance Costs...........        $14,000              $1,400              $12,000             $1,400
Compliance Costs...............         19,000               1,800              15,000               1,800
Product Recovery...............         4,600                 440                3,300                390
Net Benefits...................         34,000               3,200              36,000               3,100
                                --------------------------------------------------------------------------------
Non-Monetized Benefits.........      Climate and ozone health benefits from reducing 36 million short tons of
                                                            methane from 2023 to 2035.
                                   PM2.5 and ozone health benefits from reducing 9.7 million short tons of VOC
                                                               from 2023 to 2035.\c\
                                   HAP benefits from reducing 390 thousand short tons of HAP from 2023 to 2035.

[[Page 74714]]

 
                                          Emissions reductions from the super-emitter response program.
                                                               Visibility benefits.
                                                           Reduced vegetation effects.
----------------------------------------------------------------------------------------------------------------
\a\ Values rounded to two significant figures. Totals 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 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
  ranges from $19 billion to $130 billion ($2.1 billion to 12 billion) over 2023 to 2035 for the proposed
  option. Please see Table 3-5 and Table 3-8 of the RIA for the full range of SC-CH4 estimates. As discussed in
  Section 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. Appendix B of
  the RIA presents the results of a sensitivity analysis using a set of SC-CH4 estimates that incorporates
  recent research addressing recommendations of the National Academies of Sciences, Engineering, and Medicine
  (2017). All net benefits are calculated using climate benefits discounted at 3 percent.
\c\ A screening-level analysis of ozone benefits from VOC reductions can be found in appendix C of the RIA,
  which is included in the docket.

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 supplemental proposal and key 
technical documents at this same website and at Docket ID No. EPA-HQ-
OAR-2021-0317 located at https://www.regulations.gov/.

III. Purpose of This Regulatory Action

A. What is the purpose of this supplemental proposal?

    On November 15, 2021, the EPA published a proposed rulemaking that 
included proposed NSPS and EGs to mitigate climate-destabilizing 
pollution and to protect 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 November 2021 proposal included 
comprehensive analyses of the available data for methane and VOC 
emissions 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. 
The November 2021 proposal also solicited comment and information on 
specific topics.
    New information was received and reviewed that was not considered 
in the November 2021 proposal. As a result, changes to some of the 
standards and other provisions proposed in November 2021 are being 
proposed in this supplemental notice.
    Some of the new information was provided by commenters during the 
November 2021 proposal public comment period. Approximately 470,000 
public comment letters were submitted on the November 2021 proposal 
representing a wide range of stakeholders and state and tribal 
governments. The EPA reviewed and considered the comments received, 
including the responses to the specific solicitations for information 
and input in the development of this supplemental proposal. Several of 
the commenters

[[Page 74715]]

representing diverse stakeholder perspectives expressed general support 
for the proposal and requested that the EPA further strengthen the 
proposed standards and make them more comprehensive. Other commenters 
highlighted implementation or cost concerns related to some of the 
elements proposed in the November 2021 proposal. Some commenters also 
provided data and information that the EPA was able to use to refine or 
revise several of the standards included in the November 2021 proposal.
    This supplemental proposal only addresses specific comments that 
the EPA determined warranted changes to what was proposed. It does not 
address/summarize all of the comments submitted on the November 2021 
proposal. The EPA will continue to evaluate all the previously 
submitted comments, as well as new comments submitted on this 
supplemental action, in the development of a final NSPS OOOOb and EG 
OOOOc. All relevant comments submitted on both proposals will be 
responded to at that time.
    In summary, the purpose of this supplemental proposed rulemaking is 
to update, strengthen, and expand the standards proposed in the 
November 2021 proposal under CAA section 111(b) for methane and VOC 
emissions from new, modified, and reconstructed facilities, and the 
presumptive standards proposed under CAA section 111(d) for methane 
emissions from existing sources. In addition, this proposal: (1) 
Proposes to reduce emissions from the source category more 
comprehensively by adding proposed standards for certain sources that 
were not addressed in the November 2021 proposal, revising the proposed 
requirements for fugitive emissions monitoring and repair, and by 
establishing a super-emitter response program to target timely 
mitigation of super-emitter emissions events; (2) encourages the 
deployment of innovative technologies and techniques for detecting and 
reducing methane emissions by providing additional options for the use 
of advanced monitoring; (3) modifies and refines certain aspects of the 
proposed standards in response to concerns and information submitted in 
public comments; and (4) provides additional information not included 
in the November 2021 proposal for public comment, such as content for 
the new subparts that reflects the proposed standards and emission 
guidelines, and details of the timelines and other implementation 
requirements that apply to states to limit methane pollution from 
existing designated facilities in the source category under CAA section 
111(d).
    This supplemental notice also includes an updated RIA that accounts 
for the full impacts of these proposed actions. If finalized and 
implemented, the proposed actions in this rulemaking, as detailed in 
the November 2021 proposal and this supplemental proposal, would result 
in significant and cost-effective reductions in climate and health-
harming pollution while encouraging the continued development and 
deployment of innovative technologies to further reduce this pollution 
in the Crude Oil and Natural Gas source category.
    The summary and rationale for changes to the November 2021 proposed 
NSPS OOOOb and EG OOOOc standards are presented in section IV of this 
preamble. For each change, a high-level summary of the relevant points 
raised by commenters leading to the change is provided, followed by the 
EPA's rationale for the change. In addition to changes from the 
November 2021 proposal that are the result of public comments, the EPA 
has also included changes made as a result of additional EPA review and 
consideration of available information.
    Section V of this preamble proposes specific requirements for the 
implementation of the proposed EG to provide states with information 
needed for purposes of EG state plan development. First, we discuss 
changes to the proposed requirements for establishing standards of 
performance in state plans. Second, we discuss changes to the proposed 
components of an approvable state plan submission. Third, we discuss 
the proposed timing for state plan submissions, and changes to the 
proposed timeline for designated facilities to come into final 
compliance with the state plan.
    Section VI of this preamble includes requirements for using optical 
gas imaging in leak detection as appendix K to 40 CFR part 60 (appendix 
K). It provides an overview of the November 2021 proposal, significant 
changes made to the proposal and the basis for those changes, and a 
summary of the updated appendix K requirements.
    Section VII of this supplemental proposal includes updates to the 
impacts of the November 2021 NSPS proposal based on changes discussed 
in sections IV and V of this preamble.
    The EPA is requesting comments on all aspects of the supplemental 
proposal to enable the EPA to develop a final rule that, consistent 
with our responsibilities under section 111 of the CAA, achieves the 
greatest possible reductions in methane and VOC emissions while 
remaining achievable, cost effective, and conducive to technological 
innovation. Because this preamble includes comment solicitations/
requests on several topics and issues, we have prepared a separate 
memorandum that presents these comment requests by section and topic as 
a guide to assist commenters in preparing comments. This memorandum and 
supporting materials can be obtained from the Docket for this action 
(see Docket ID No. EPA-HQ-OAR-2021-0317). The title of the memorandum 
is ``Standards of Performance for New, Reconstructed, and Modified 
Sources and Emissions Guidelines for Existing Sources: Oil and Natural 
Gas Sector Climate Review--Supplemental Proposed Rule Summary of 
Comment Solicitations.''

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

    For the reasons explained below, NSPS OOOOb would apply to all 
emissions sources (``affected facilities'') identified in the proposed 
40 CFR 60.5365b, except dry seal centrifugal compressors, that 
commenced construction, reconstruction, or modification after November 
15, 2021. NSPS OOOOb would apply to dry seal centrifugal compressor 
affected facilities that commence construction, reconstruction, or 
modification after December 6, 2022.
    Pursuant to CAA section 111(b), the EPA proposed new source 
performance standards (NSPS) for a wide range of emissions sources in 
the Crude Oil and Natural Gas source category (to be codified in 40 CFR 
part 60 subpart OOOOb) in a Federal Register notice published November 
15, 2021. Some of the proposed standards resulted from the EPA's review 
of the current NSPS codified at 40 CFR part 60 subpart OOOOa (NSPS 
OOOOa), while others were proposed standards for additional emissions 
sources that are currently unregulated. The emissions sources for which 
the EPA proposed standards in the November 2021 proposal are as 
follows:

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

[[Page 74716]]

 Sweetening units

    These standards of performance would apply to ``new sources.'' CAA 
section 111(a)(2) defines a ``new source'' as ``any stationary source, 
the construction or modification of which is commenced after the 
publication of regulations (or, if earlier, proposed regulations) 
prescribing a standard of performance under this section which will be 
applicable to such source.'' Because the proposed regulation proposing 
the standards for these emission sources was published November 15, 
2021, ``new sources'' to which these standards apply are those that 
commenced construction, reconstruction, or modification after November 
15, 2021.
    We received comments on the November 2021 proposal that it lacks 
regulatory text and therefore should not be used to define new sources 
for purposes of NSPS OOOOb.\11\ The EPA disagrees for the following 
reasons. CAA section 307(d)(3) specifies the information that a 
proposed rule under the CAA must contain, such as a statement of basis, 
supporting data, and major legal and policy considerations; the list of 
required information does not include proposed regulatory text. 
Similarly, the Administrative Procedures Act (APA), which governs most 
Federal rulemaking, does not require publication of the proposed 
regulatory text in the Federal Register. Section 553(b)(3) of the APA 
provides that a notice of proposed rulemaking shall include ``either 
the terms or substance of the proposed rule or a description of the 
subjects and issues involved.'' (Emphasis added). Thus, the APA clearly 
provides flexibility to describe the ``subjects and issues involved'' 
as an alternative to inclusion of the ``terms or substance'' of the 
proposed rule. See also Rybachek v. EPA, 904 F.2d 1276, 1287 (9th Cir. 
1990) (the EPA's ``failure to propose in advance the actual wording'' 
of a regulation does not make the regulation invalid where the 
``proposal . . . clearly describe[s] `the subjects and issues' '' 
involved). The EPA solicits comments on whether CAA section 111(a) 
provides the EPA discretion to define ``new sources'' based on the 
publication date of a supplemental proposal and, if so, whether there 
are any unique circumstances here that would warrant the exercise of 
such discretion in this rulemaking by the EPA.
---------------------------------------------------------------------------

    \11\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0424, EPA-HQ-OAR-
2021-0317-0539, EPA-HQ-OAR-2021-0317-0579, EPA-HQ-OAR-2021-0317-
0598, EPA-HQ-OAR-2021-0317-0599, EPA-HQ-OAR-2021-0317-0815, and EPA-
HQ-OAR-2021-0317-0929.
---------------------------------------------------------------------------

    In addition to the proposed standards, this supplemental proposal 
includes proposed standards for an additional emissions source, 
specifically dry seal centrifugal compressors. Because the EPA is 
proposing standards for dry seal centrifugal compressors for the first 
time in this supplemental proposal, ``new sources'' to which these 
standards apply are dry seal centrifugal compressors that commence 
construction, reconstruction, or modification after the date this 
supplemental proposal is published, which is December 6, 2022.

C. What date defines an existing source for purposes of the proposed EG 
OOOOc?

    The November 2021 proposal also included proposed emissions 
guidelines for states to follow and develop plans to regulate existing 
sources in the Crude Oil and Natural Gas source category under EG 
OOOOc. Under CAA section 111, a source is either new, i.e., 
construction, reconstruction, or modification commenced after a 
proposed NSPS is published in the Federal Register (CAA section 
111(a)(1)), or existing, i.e., any source other than a new source (CAA 
section 111(a)(6)). Accordingly, any source that is not subject to the 
proposed NSPS OOOOb as described is an existing source subject to EG 
OOOOc. As explained, new sources, with the exception of dry seal 
centrifugal compressors, are those that commenced construction, 
reconstruction, or modification after November 15, 2021; therefore, 
existing sources are those that commenced construction, reconstruction, 
or modification on or before November 15, 2021. Similarly, because new 
dry seal centrifugal compressors are those that commenced construction, 
reconstruction, or modification after December 6, 2022, existing dry 
seal centrifugal compressors are those that commenced construction, 
reconstruction, or modification on or before December 6, 2022.

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

    Sources currently subject to 40 CFR part 60, subpart KKK (NSPS 
KKK), 40 CFR part 60 subpart OOOO (NSPS OOOO), or NSPS OOOOa would 
continue to comply with their respective standards until a state or 
Federal plan implementing EG OOOOc becomes effective. For most 
designated facilities, the EPA proposes to conclude that compliance 
with the implementing state or Federal plan that is consistent with the 
presumptive standards in EG OOOOc would constitute compliance with the 
older NSPS because the presumptive standards proposed for EG OOOOc 
result in the same or greater emission reductions than the current 
standards in the older NSPS.
    In this rulemaking, the EPA is proposing standards for dry seal 
centrifugal compressor and intermittent bleed pneumatic controllers for 
the first time in NSPS OOOOb and EG OOOOc. Because these designated 
facilities (i.e., dry seal centrifugal compressors and intermittent 
bleed pneumatic controllers) are not subject to regulation under a 
previous NSPS, they only need to comply with the state or Federal plan 
implementing EG OOOOc. The EPA is proposing presumptive standards for 
fugitive emissions at compressor stations, pneumatic pumps at natural 
gas processing plants, and pneumatic controllers at natural gas 
processing plants that are all the same or greater stringency than NSPS 
KKK, NSPS OOOO, and NSPS OOOOa, as applicable. Therefore, compliance 
with the state or Federal plan implementing EG OOOOc would satisfy 
compliance with the respective NSPS regulation. Additionally, the 
proposed presumptive standards in EG OOOOc for pneumatic pumps 
(excluding processing) and natural gas processing plant equipment leaks 
are more stringent than the standards in NSPS OOOOa for pneumatic pumps 
and all three NSPS for natural gas processing plant equipment leaks, 
and therefore compliance with the state or Federal plan implementing EG 
OOOOc would satisfy compliance with the respective NSPS regulation.
    For wet seal centrifugal compressors, two different standards are 
in place for the older NSPS. NSPS KKK is an equipment standard that 
provides several compliance options including: (1) Operating the 
compressor with the barrier fluid at a pressure that is greater than 
the compressor stuffing box pressure; (2) equipping the compressor with 
a barrier fluid system degassing reservoir that is routed to a process 
or fuel gas system, or that is connected by a CVS to a control device 
that reduces VOC emissions by 95 percent or more; or (3) equipping the 
compressor with a system that purges the barrier fluid into a process 
stream with zero VOC emissions to the atmosphere. NSPS KKK exempts 
compressors from these requirements if it is either equipped with a 
closed vent system to capture and transport leakage from the compressor 
drive shaft back to a process or fuel gas system or to a control device

[[Page 74717]]

that reduces VOC emissions by 95 percent, or if it is designated for no 
detectable emissions. NSPS OOOO and NSPS OOOOa require 95 percent 
reduction of emissions from each centrifugal compressor wet seal fluid 
degassing system. NSPS OOOO and OOOOa also allow the alternative of 
routing the emissions to a process. The proposed presumptive standards 
under EG OOOOc would be a numerical emission limit of 3 scfm, as 
described in IV.G. of this preamble, and includes an alternative 
compliance option to reduce methane emissions by 95 percent by routing 
to a control or process. The proposed presumptive standard of 3 scfm is 
less stringent than the standards in NSPS OOOO and OOOOa, and 
therefore, compliance with a state or Federal plan implementing EG 
OOOOc using the 3 scfm presumptive standard would not satisfy 
compliance with NSPS OOOO and NSPS OOOOa for wet seal centrifugal 
compressor designated facilities. However, the EPA is not aware of any 
wet seal centrifugal compressors subject to NSPS OOOO or NSPS OOOOa and 
the EPA believes that centrifugal compressors installed since those 
rules went into effect (August 2011 and September 2015) are utilizing 
dry seals rather than wet seals. For wet seal centrifugal compressors 
currently subject to KKK (those designated as new sources between 
January 1984 and August 2011), compliance with NSPS KKK would allow for 
compliance with the state or Federal plan implementing EG OOOOc because 
the zero emissions limit would also achieve the 3 scfm limit proposed 
in EG OOOOc. For an owner or operator who uses the alternative 
compliance method proposed in EG OOOOc of routing to a control or 
process, achieving 95 percent emissions reductions can be accomplished 
using the same compressor requirements as required in NSPS OOOOa. Thus, 
compliance with a state or Federal plan implementing EG OOOOc using the 
95 percent control alternative would satisfy compliance with NSPS OOOO 
and NSPS OOOOa for wet seal centrifugal compressor designated 
facilities.
    The NSPS KKK standard is more stringent than the proposed 3 scfm 
presumptive standard in EG OOOOc for methane emissions. Accordingly, 
for centrifugal compressors, NSPS KKK would still apply to compressors 
at natural gas processing plants for which construction, 
reconstruction, or modification commenced after January 20, 1984, and 
on or before August 23, 2011.
    There are two different standards for reciprocating compressors in 
the older NSPS: (1) NSPS KKK requires the use of a seal system and 
includes a barrier fluid system that prevents leakage of VOC to the 
atmosphere for reciprocating compressors located at natural gas 
processing plants, and (2) NSPS OOOO and NSPS OOOOa require changing 
out the rod packing every 3 years or routing emissions to a control. 
The proposed presumptive standard for EG OOOOc is a volumetric flow 
rate of 2 scfm. The proposed BSER is to repair and/or replace the 
reciprocating compressor rod packing in order to maintain the flow rate 
at or below 2 scfm (based on annual monitoring and additional 
preventative or corrective measures) and includes an alternative 
compliance option to route emissions to a process, as described in 
IV.I. of this preamble.
    The NSPS KKK standard is more stringent than the proposed 2 scfm 
presumptive standard in EG OOOOc for methane emissions. Accordingly, 
for reciprocating compressors subject to NSPS KKK, the NSPS KKK 
provisions would still apply to reciprocating compressors at natural 
gas processing plants for which construction, reconstruction, or 
modification commenced after January 20, 1984, and on or before August 
23, 2011. For NSPS KKK, several provisions effectively exempt certain 
reciprocating compressors at natural gas processing plants from the 
seal system requirements, including: an exemption for reciprocating 
compressors in wet gas service, a requirement that reciprocating 
compressors must be in VOC service (i.e., at least 10 percent by weight 
VOC in the process fluid in contact with the compressor) for standards 
to apply, and an exemption for reciprocating compressors designated 
with no detectable emissions. If a reciprocating compressor at a 
natural gas processing plant was constructed, reconstructed, or 
modified between January 20, 1984, and August 23, 2011, is exempt from 
the provisions of NSPS KKK due to one of these conditions, it would be 
subject to the requirements of the state or Federal plan implementing 
EG OOOOc.
    As explained in section XII.E.1.d. of the November 2021 proposal 
\12\ and section IV.I of this preamble, the EPA finds that the proposed 
EG OOOOc standard is more efficient at discovering and reducing any 
emissions that may develop than the set 3-year replacement interval 
from NSPS OOOO and NSPS OOOOa. Overall, the proposed presumptive 
standards would produce more rod packing replacements, thereby reducing 
more emissions compared to the 3-year interval. Therefore, the EPA is 
proposing that compliance with the state or Federal plan implementing 
EG OOOOc will satisfy compliance with the respective NSPS OOOO and 
OOOOa regulations for reciprocating compressor designated facilities.
---------------------------------------------------------------------------

    \12\ 86 FR 63215 to 63220 (November 15, 2021).
---------------------------------------------------------------------------

    The affected facility for storage vessels is defined in the NSPS 
OOOO and NSPS OOOOa as a single storage vessel with the potential to 
emit greater than 6 tons of VOC per year and the standard that applies 
is 95 percent emissions reduction. Under the proposed EG OOOOc, the 
designated facility is a tank battery with the potential to emit 
greater than 20 tons of methane per year with the same 95 percent 
emission reduction standard, as discussed in IV.J. of this preamble. 
Affected facilities under NSPS OOOO or OOOOa that are part of a 
designated facility under the EG would be required to meet the 95 
percent reduction standard, and therefore would satisfy their 
respective NSPS requirement to do the same. Affected facilities under 
NSPS OOOO or OOOOa that emit 6 tpy or more of VOCs but that do not meet 
the potential to emit 20 tons of methane per year definition would 
continue to comply with the 95-percent emissions reduction standard in 
their respective NSPS. Scenarios regarding further physical or 
operational changes in NSPS OOOOb that would reclassify sources from 
the older NSPS and/or EG OOOOc into NSPS OOOOb are discussed in section 
IV.J.1.b. of this preamble.
    Similarly, pneumatic controller affected facilities not located at 
natural gas processing plants are defined as single high-bleed 
controllers with a low-bleed standard under NSPS OOOO and NSPS OOOOa, 
while the designated facility under EG OOOOc is defined as a collection 
of natural gas-driven pneumatic controllers at a site with a zero 
emissions standard (discussed further in Section IV.D. of this 
preamble). The proposed zero-emissions presumptive standard in EG OOOOc 
is more stringent than the low-bleed standard found in the older NSPS, 
therefore the EPA is proposing that compliance with the state or 
Federal plan implementing EG OOOOc would satisfy compliance with the 
respective NSPS regulation for pneumatic controllers not located at a 
natural gas processing plant.
    Lastly, standards for fugitive emissions from well sites under NSPS 
OOOOa require semiannual OGI monitoring on all components at the well 
site except for wellhead only well sites (which are not affected 
facilities), while the presumptive standards under the proposed EG 
OOOOc would require quarterly OGI monitoring at well sites

[[Page 74718]]

with major production and processing equipment, semiannual OGI combined 
with quarterly AVO inspections at multi-wellhead only well sites,\13\ 
and quarterly AVO inspections for small sites and single wellhead well 
sites, as described in section IV.A of this preamble. It is clear that 
the proposed presumptive standards for well sites with major production 
and processing equipment and the proposed presumptive standards for 
multi-wellheads only well sites are both more stringent than the 
semiannual OGI monitoring standard under NSPS OOOOa because one would 
require more frequent OGI monitoring while the other would require AVO 
inspections in addition to semiannual OGI monitoring; therefore, for 
these existing wellsites that are also subject to NSPS OOOOa, 
compliance with proposed presumptive standards would be deemed in 
compliance with the semiannual OGI monitoring standard in NSPS OOOOa. 
With respect to existing single wellhead only well sites and small 
sites that are also subject to the semiannual monitoring under NSPS 
OOOOa, the EPA is proposing that compliance with the proposed 
presumptive standards, specifically quarterly AVO, would satisfy NSPS 
OOOOa for the following reasons. First, as explained in more detail in 
section IV.A, AVO is effective, and therefore OGI is unnecessary, for 
detecting fugitive emissions from many of the fugitive emissions 
components at these sites. Second, by requiring more frequent visits to 
the sites, the proposed presumptive standard would allow earlier 
detection and repair of fugitive emissions, in particular large 
emissions from components such as thief hatches on uncontrolled storage 
vessels. In light of the above, the EPA finds that the presumptive 
standards under the proposed EG OOOOc would effectively address the 
fugitive emissions at these well sites, and that semiannual OGI 
monitoring would no longer be necessary for these well sites that are 
also subject to NSPS OOOOa. For the reasons stated above, the EPA is 
proposing to conclude that compliance with the state or Federal plan 
implementing the presumptive fugitive emissions standards in the 
proposed EG OOOOc may be deemed to satisfy compliance with monitoring 
standards (i.e., semiannual monitoring using OGI) in NSPS OOOOa for all 
well sites.
---------------------------------------------------------------------------

    \13\ Because of a difference in the definition of a wellhead 
only well site in NSPS OOOOa and the proposed EG OOOOc, some single 
and multi-wellhead only well sites could be subject to the 
semiannual OGI monitoring under NSPS OOOOa.
---------------------------------------------------------------------------

    The EPA is soliciting comment on all aspects of the proposed 
comparison of standards in the older NSPS to the proposed presumptive 
standards in EG OOOOc. Specifically, the EPA is requesting comment 
relevant to the comparison of stringency for compressors (both 
centrifugal and reciprocating) to NSPS KKK and for fugitive emissions 
monitoring at small well sites.

E. How does the EPA consider costs in this supplemental proposal?

    In the November 2021 proposal, the EPA described the various 
approaches for evaluating control costs in its BSER analyses. 86 FR 
63154-63157 (November 15, 2021). As described in that document, in 
considering the costs of the control options evaluated in this action, 
the EPA estimated the control costs under various approaches, including 
annual average cost-effectiveness and incremental cost-effectiveness of 
a given control. In its cost-effectiveness analyses, the EPA recognized 
and took into account that these multi-pollutant controls reduce both 
VOC and methane emissions in equal proportions, as reflected in the 
single-pollutant and multipollutant cost effectiveness approaches for 
the proposed NSPS OOOOb. The EPA also considered cost saving from the 
natural gas recovered instead of vented due to the proposed controls. 
In both the November 2021 proposal \14\ and this supplemental 
proposal,\15\ the EPA proposes to find that cost-effectiveness values 
up to $5,540/ton of VOC reduction are reasonable for controls that we 
have identified as BSER and within the range of what the EPA has 
historically considered to represent cost effective controls for the 
reduction of VOC emissions. Similarly, for methane, the EPA finds the 
cost-effectiveness values up to $1,970/ton of methane reduction to be 
reasonable for controls that we have identified as BSER in both the 
November 2021 proposal and this supplemental proposal, well below the 
$2,185/ton \16\ of methane reduction that EPA has previously found to 
be reasonable for the industry.
---------------------------------------------------------------------------

    \14\ 86 FR 63155 (November 15, 2021).
    \15\ See November 2021 TSD at Document ID No. EPA-HQ-OAR-2021-
0317-0166 and Supplemental TSD for this action located at Docket ID 
No. EPA-HQ-OAR-2021-0317.
    \16\ 80 FR 56627 (June 6, 2016). See also, ``Background 
Technical Support Document for the New Source Performance Standards 
40 CFR part 60 subpart OOOOa (May 2016)'', at page 93, Table 6-7 
located at Document ID No. EPA-HQ-OAR-2010-0505-7631.
---------------------------------------------------------------------------

    For this supplemental proposal, we also updated the two additional 
analyses that the EPA performed for the November 2021 proposal to 
further inform our determination of whether the cost of control of the 
collection of proposed standards would be reasonable, similar to 
compliance cost analyses we have completed for other NSPS.\17\ The two 
additional analyses include: (1) A comparison of the capital costs 
incurred by compliance with the proposed rules to the industry's 
estimated new annual capital expenditures, and (2) a comparison of the 
annualized costs that would be incurred by compliance with the proposed 
standards to the industry's estimated annual revenues. In this section, 
the EPA provides updated information regarding these cost analyses 
based on the proposed standards described in this notice. See 86 FR 
63156 (November 15, 2021) for additional discussion on these two 
analyses.
---------------------------------------------------------------------------

    \17\ For example, see our compliance cost analysis in 
``Regulatory Impact Analysis (RIA) for Residential Wood Heaters NSPS 
Revision. Final Report.'' U.S. Environmental Protection Agency, 
Office of Air Quality Planning and Standards. EPA- 452/R-15-001, 
February 2015.
---------------------------------------------------------------------------

    First, for the capital expenditures analysis, the EPA divided the 
nationwide capital expenditures projected to be spent to comply with 
the proposed standards by an estimate of the total sector-level new 
capital expenditures for a representative year to determine the 
percentage that the nationwide capital cost requirements under the 
proposal represent of the total capital expenditures by the sector. We 
combine the compliance-related capital costs under the proposed 
standards for the NSPS and for the presumptive standards in the 
proposed EG to analyze the potential aggregate impact of the proposal. 
The EAV of the projected compliance-related capital expenditures over 
the 2023 to 2035 period is projected to be about $1.4 billion in 2019 
dollars. We obtained new capital expenditure data for relevant NAICS 
codes for 2019 from the U.S. Census 2020 Annual Capital Expenditures 
Survey.\18\ While Census data on capital expenditures are available for 
2020, these figures were heavily influenced by COVID-19-related impacts 
such that 2020 does is not an appropriate representative year to use in 
this analysis. According to these data, new capital expenditures for 
the sector in 2019 were about $156 billion in 2019

[[Page 74719]]

dollars.\19\ Note that new capital expenditures for pipeline 
transportation of natural gas (NAICS 4862) includes only expenditures 
on structures as data on expenditures on equipment data are withheld to 
avoid disclosing data for individual enterprises. As a result, the 
capital expenditures used here represent an underestimate of the 
sector's expenditures. Comparing the EAV of the projected compliance-
related capital expenditures under the proposal with the 2019 total 
sector-level new capital expenditures yields a percentage of about 0.9 
percent, which is well below the percentage increase previously upheld 
by the courts.
---------------------------------------------------------------------------

    \18\ U.S. Census Bureau, 2020 Annual Capital Expenditures 
Survey, Table 4b. Capital Expenditures for Structures and Equipment 
for Companies with Employees by Industry: 2019 Revised, https://www.census.gov/data/tables/2020/econ/aces/2020-aces-summary.html, 
accessed 7/12/2022.
    \19\ The total capital expenditures for the same NAICS codes 
during COVID 19-impacted 2020 were about $90 billion.
---------------------------------------------------------------------------

    Second, for the comparison of compliance costs to revenues, we use 
the EAV of the projected compliance costs without and with projected 
revenues from product recovery under the proposal for the 2023 to 2035 
period then divided the nationwide annualized costs by the annual 
revenues for the appropriate NAICS code(s) for a representative year to 
determine the percentage that the nationwide annualized costs represent 
of annual revenues. Like we do for capital expenditures, we combine the 
costs projected to be expended to comply with the standards for NSPS 
and the presumptive standards in the proposed EG to analyze the 
potential aggregate impact of the proposal. The EAV of the associated 
increase in compliance cost over the 2023 to 2035 period is projected 
to be about $1.7 billion without revenues from product recovery and 
about $1.2 billion with revenues from product recovery (in 2019 
dollars). Revenue data for relevant NAICS codes were obtained from the 
U.S. Census 2017 County Business Patterns and Economic Census, the most 
recent revenue figures available.\20\ According to these data, 2017 
receipts for the sector were about $358 billion in 2019 dollars. 
Comparing the EAV of the projected compliance costs under the proposal 
with the sector-level receipts figure yields a percentage of about 0.5 
percent without revenues from product recovery and about 0.4 percent 
with revenues from product recovery. More data and analysis supporting 
the comparison of capital expenditures and annualized costs projected 
to be incurred under the rule and the sector-level capital expenditures 
and receipts is presented in the TSD for this action, which is in the 
public docket.
---------------------------------------------------------------------------

    \20\ 2017 County Business Patterns and Economic Census. The 
Number of Firms and Establishments, Employment, Annual Payroll, and 
Receipts by Industry and Enterprise Receipts Size: 2017, https://www.census.gov/programs-surveys/susb/data/tables.2017.html, accessed 
September 4. 2021. Note receipts data are available only for 
Economic Census years (years ending in 2 and 7) so 2017 data remains 
the most recent data available.
---------------------------------------------------------------------------

    In considering the costs of the control options evaluated in this 
action, the EPA estimated the control costs under various approaches, 
including annual average cost-effectiveness and incremental cost-
effectiveness of a given control. In its cost-effectiveness analyses, 
the EPA recognized and took into account that these multi-pollutant 
controls reduce both VOC and methane emissions in equal proportions, as 
reflected in the single-pollutant and multipollutant cost effectiveness 
approaches for the proposed NSPS OOOOb. The EPA also considered cost 
saving from the natural gas recovered instead of vented due to the 
proposed controls. Based on all of the considerations described, the 
EPA concludes that the costs of the controls that serve as the basis of 
the standards proposed in this action are reasonable. The EPA solicits 
comment on its approaches for considering control costs, as well as the 
resulting analyses and conclusions.

F. Legal Basis for Rulemaking Scope

    In the November 2021 proposal, the EPA described the regulatory 
history of its authority to regulate methane emissions from the oil and 
gas source category under CAA section 111. The EPA explained that the 
2016 Rule, 81 FR 35823 (June 3, 2016), established the agency's 
authority to regulate these methane emissions; the 2020 Policy Rule, 85 
FR 57018 (September 14, 2020) had rescinded certain parts of the 2016 
Rule, including its authorization to regulate methane; and a joint 
resolution under the Congressional Review Act (CRA), signed into law by 
President Biden on June 30, 2021, had rescinded the 2020 Policy Rule, 
and thereby reinstated the 2016 Rule's authorization to regulate 
methane. 86 FR 63135-36 (November 15, 2021).
    In describing this history, the EPA noted that in the 2016 Rule, in 
response to comments, the EPA had explained that once it had listed a 
source category for regulation under section 111(b)(1)(A), it was not 
required to make, as a predicate to regulating GHG emissions from the 
source category, an additional pollutant-specific finding that those 
GHG emissions contribute significantly to dangerous air pollution 
(termed, a pollutant-specific significant contribution finding). 
However, in the alternative, the 2016 Rule did make such a finding, 
relying on information concerning the large amounts of methane 
emissions from the source category. 86 FR 63135 (November 15, 2021) 
(citing 81 FR 35843; June 3, 2016). The November 2021 proposal further 
noted that in the legislative history of the CRA resolution, Congress 
made clear its intent that section 111 did not require or authorize a 
pollutant-specific significant contribution finding, and the EPA 
confirmed that it agreed with that interpretation. 86 FR 63148 
(November 15, 2021).
    Some commenters on the November 2021 proposal reiterated the 
argument that the EPA is required to make a pollutant-specific 
significant contribution finding for GHG emissions from the oil and gas 
source category and stated that in order to make such a finding, the 
EPA must identify a standard or criteria for when a contribution is 
significant.\21\ We may respond further to these comments in the final 
rule, but the November 2021 proposal notes that the legislative history 
of the CRA joint resolution rejected the position that a standard or 
criteria is necessary for determining significance, and explained, ``It 
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.'' 86 FR 63151 (November 15, 2021) 
(quoting House Report at 11). That continues to be the EPA's view and 
is consistent with decades of practice under section 111. The EPA has 
listed dozens of source categories, beginning in 1971,\22\ in many 
cases on the basis of multiple pollutants emitted by the particular 
source category,\23\ and has never identified a standard or criteria 
for determining significance.
---------------------------------------------------------------------------

    \21\ Comments of Permian Basin Petroleum Ass'n, Document ID No. 
EPA-HQ-OAR-2021-0317-0793 at 3-4 (citing 85 FR 57018, 57038 
(September 14, 2020).
    \22\ List of Categories of Stationary Sources, 36 FR 5931 (March 
31, 1971); see 40 CFR part 60.
    \23\ For example, when it listed ``stationary gas turbines'' as 
a source category, EPA considered emissions of particulates, 
nitrogen oxides, sulfur dioxide, carbon monoxide, and hydrocarbons. 
Addition to the List of Categories of Stationary Sources, 42 FR 
53657 (October 3, 1977); Standards of Performance for New Stationary 
Sources: Proposed rule, 42 FR 53782, 53783 (October 3, 1977).
---------------------------------------------------------------------------

    If the EPA were required to develop a standard or criteria to 
determine significance, any reasonable set of criteria would 
necessarily focus on the amount of emissions from the source category 
and the harmfulness of the pollutant emitted. In the case of the oil 
and gas source category, the ``massive quantities of methane 
emissions''

[[Page 74720]]

contributed by the sector to the levels of well-mixed GHG in the 
atmosphere, as described in the November 2021 proposal, 86 FR 63148 
(November 15, 2021), coupled with the potency of methane (with a global 
warming potential (GWP) of almost 30 or more than 80, depending on the 
time period of the impacts, 86 FR 63130; November 15, 2021), 
demonstrate that the source category's GHG emissions would be 
significant under any rational criteria-based approach. More 
specifically, as the EPA stated in the November 2021 proposal, as 
illustrated by the domestic and global GHGs comparison data summarized 
in that notice, 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. See 86 FR 63131 (November 15, 
2021).
    The large quantity of methane emitted by the oil and gas source 
category is brought into sharp relief by the fact that, as the November 
2021 proposal further stated, 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. See 
86 FR 63131 (November 15, 2021).
    Importantly, the oil and gas source category is the largest emitter 
of methane of any source category in the United States. 86 FR 63129 
(November 15, 2021). As described in the November 2021 proposal, 
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, one third of 
the warming due to GHGs that we are experiencing today is due to human 
emissions of methane. See 86 FR 63129 (November 15, 2021).
    The large amounts of methane emissions from the oil and gas source 
category in relation to other domestic and global sources of methane, 
coupled with the harmfulness of methane, should be considered more than 
sufficient to satisfy any criterion or standard for evaluating 
significant contribution. In particular, in the context of a problem 
like climate change that is caused by the collective contribution of 
many different sources, the fact that the oil and gas source category 
has the largest amount of methane emissions in the United States 
confirms that those emissions would meet a criterion or standard for 
significance.\24\
---------------------------------------------------------------------------

    \24\ The EPA acknowledges that the collective nature of the 
climate change problem means it will likely also be appropriate to 
regulate other source categories of methane emissions that are not 
necessarily as large as the oil and gas source category, cf. EPA v. 
EME Homer City, 572 U.S. 489, 514 (2014) (affirming framework to 
address ``the collective and interwoven contributions of multiple 
upwind States'' to ozone nonattainment), as indicated by the fact 
that EPA has long regulated landfill gas, which consists of methane 
in 50 percent part. ``Emission Guidelines and Compliance Times for 
Municipal Solid Waste Landfills; Final Rule,'' 81 FR 59276, 59281 
(August 29, 2016). But this does not mean that it would be 
appropriate to regulate all other types of sources, even ones with 
few emissions. In the past, the EPA has declined to regulate air 
pollutants emitted from source categories in quantities too small to 
be worrisome and because regulation would have produced little 
environmental benefit. See Nat'l Lime Ass'n. v. EPA, 627 F.2d 416, 
426 & n.27 (D.C. Cir. 1980) (small amounts of emissions of nitrogen 
oxides and carbon monoxide from lime kilns was a key factor in EPA 
decision not to promulgate new source performance standards for 
those pollutants; citing Standards of Performance for New Stationary 
Sources Lime Manufacturing Plants--Proposed Rule, 42 FR 22506, 22507 
(May 3, 1977)).
---------------------------------------------------------------------------

G. Inflation Reduction Act

    The Inflation Reduction Act (IRA) was signed into law on August 16, 
2022. Section 60113 of the IRA amended the CAA by adding section 136, 
``Methane Emissions and Waste Reduction Incentive Program for Petroleum 
and Natural Gas Systems.'' Under this new section of the CAA, 
subsection 136(c), ``Waste Emission Charge,'' requires the 
Administrator to ``impose and collect a charge on methane emissions 
that exceed an applicable waste emissions threshold under subsection 
(f) from an owner or operator of an applicable facility that reports 
more than 25,000 metric tons of carbon dioxide equivalent of greenhouse 
gases emitted per year pursuant to subpart W of part 98 of title 40, 
Code of Federal Regulations (40 CFR part 98), regardless of the 
reporting threshold under that subpart.'' An ``applicable facility'' is 
defined under CAA section 136(d) by reference to specific industry 
segments as defined in the 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''). Pursuant to CAA 
section 136(g), the charge is to be imposed and collected beginning 
with respect to emissions reported for calendar year 2024 and for each 
year thereafter.
    CAA section 136(f) identifies several circumstances under which the 
charges shall not be imposed on an owner or operator of an affected 
facility. In particular, CAA section 136(f)(6)(A) states that ``charges 
shall not be imposed pursuant to subsection (c) on an applicable 
facility that is subject to and in compliance with methane emissions 
requirements pursuant to subsections (b) and (d) of section 111 upon a 
determination by the Administrator that:
    (i) Methane emissions standards and plans pursuant to subsections 
(b) and (d) of section 111 have been approved and are in effect in all 
States with respect to the applicable facilities; and
    (ii) compliance with the requirements described in clause (i) will 
result in equivalent or greater emissions reductions as would be 
achieved by the proposed rule of the Administrator entitled `Standards 
of Performance for New, Reconstructed, and Modified Sources and 
Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector 
Climate Review' (86 FR 63110 (November 15, 2021)), if such rule had 
been finalized and implemented.''
    Per section 136(c)(6)(B) ``if the conditions in clause (i) or (ii) 
of subparagraph (A) cease to apply after the Administrator has made the 
determination in that subparagraph, the applicable facility will again 
be subject to the charge under subsection (c) beginning in the first 
calendar year in which the conditions in either clause (i) or (ii) of 
that subparagraph are no longer met.''
    The EPA intends to take one or more separate actions in the future 
to implement the Methane Emissions and Waste Reduction Incentive 
Program, including revisions to certain requirements of GHGRP subpart 
W, and will provide an opportunity for public comment on the 
implementation of the Methane Emissions and Waste Reduction Incentive 
Program in those actions. Accordingly, the EPA considers the 
implementation of the Methane Emissions and Waste Reduction Incentive 
Program to be outside the scope of this supplemental proposed rule. 
However, the EPA is requesting comments on the criteria and approaches 
that the Administrator

[[Page 74721]]

should consider in making the CAA section 136(f)(6)(A)(ii) 
determination (``IRA equivalence determination'') because the EPA 
expects that the public and regulated industry will be interested in 
how the scope of the final oil and gas standards and emission 
guidelines may influence the applicability of the statutory exemption.
    With respect to CAA section 136(f)(6)(A)(ii), the Administrator 
must determine that the methane emission standards in effect pursuant 
to CAA sections 111(b) and (d) ``will result in equivalent or greater 
emissions reductions as would be achieved'' by the EPA's November 2021 
proposed rule. As a general matter, the EPA believes that the changes 
being proposed in today's action do not reduce expected methane 
emission reductions relative to the November 2021 proposal. Instead, 
the EPA anticipates that most, if not all, of the proposed changes 
contained in this supplemental proposal would likely lead to greater 
methane emissions reductions when fully implemented. For this reason, 
the Agency further anticipates that promulgation of Federal and state 
standards consistent with this supplemental proposal would result in 
methane emissions reductions at least as great as the November 2021 
proposal. However, at this point, the EPA's analysis is purely 
qualitative. The EPA does not believe that it is appropriate to 
quantitatively compare the emission reductions from the November 2021 
proposal and this supplemental proposal because, as is discussed in 
section 1.3 of the RIA, the analysis of this supplemental proposal 
includes key updates to assumptions and methodologies that impact both 
the baseline and policy scenarios. As such, the estimated impacts 
presented in the RIA of this supplemental proposal are not directly 
comparable to corresponding estimates presented in the RIA of the 
November 2021 proposal.
    Moreover, the statutory language in CAA section 136(f)(6)(A)(ii) 
does not indicate how the EPA should conduct this equivalency 
evaluation and what factors should influence how the EPA conducts the 
comparison. Because of this ambiguity in the statutory language, the 
EPA is requesting comments on how to best conduct this evaluation and 
on factors and assumptions the EPA should consider in conducting such 
an evaluation.
    First, the EPA seeks comments on temporal elements of the 
evaluation. The EPA believes that the appropriate temporal comparison 
should be based on when requirements are fully implemented by the 
sources (i.e., if a state phases in installation of zero-emitting 
pneumatic controllers over more than one year, the comparison should be 
made at the point that the emission guidelines require full use of 
zero-emitting controllers). The EPA seeks comment on this approach 
versus an alternative such as making a multi-year comparison beginning 
with the effective date of the rule. In either case, as discussed 
below, such a determination could be made prospectively based either on 
the rule finalized by the EPA or when state plans have been approved. 
As discussed in section V.D. of the supplemental proposal, the EPA is 
proposing to require the submission of state plans under EG OOOOc 
within 18 months after publication of the final EG. In addition, 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 36 months following the state plan submittal deadline.
    Second, the EPA seeks comments on geographical elements of the 
evaluation. Per the statutory language in CAA section 136(f)(6)(A)(i), 
the EPA's evaluation is to be done with respect to all states. The EPA 
requests comments on whether we should consider making a national 
evaluation of equivalency or whether we should consider a state-by-
state evaluation instead. Under a national evaluation, the EPA 
envisions conducting an assessment of the reductions achieved across 
all states and then evaluating those reductions collectively against 
the collective reductions anticipated from implementation of the 
November 2021 proposal. Under a state-by-state evaluation, the EPA 
envisions needing to analyze whether every state is achieving 
equivalent or greater reductions than that state would have achieved 
under the November 2021 proposal.
    Third, the EPA requests comments on whether the EPA should make the 
evaluation and the IRA equivalency determination in advance of states 
having submitted fully approvable plans or instead make the evaluation 
and IRA equivalency determination at a later date once the standards of 
performance pursuant to CAA section 111(b) and 111(d) are fully 
promulgated (e.g., the EPA has approved state plans and/or developed a 
Federal Plan). In particular, the EPA request comments on whether the 
EPA's analysis should compare the November 2021 EG proposal and final 
EG OOOOc by assuming designated facilities would be subject to their 
corresponding EG presumptive standards once state plans are 
implemented, or whether we should compare the November 2021 EG proposal 
to the actual state plans that are approved. As to the latter approach, 
the EPA seeks comments on how a state's invocation of RULOF to apply a 
less stringent standard to a designated facility might affect the 
equivalency evaluation and IRA equivalency determination. In 
establishing standards of performance for individual sources, CAA 
section 111(d) and the EPA's regulations provide that states may invoke 
RULOF for the application of less stringent standards provided they 
meet the certain requirements established in the EPA's regulations and 
the EG (see section V.B.3 below). As a result, it is possible that 
those state plans (individually or collectively) may not result in 
equivalent or greater emissions reductions as would be achieved by full 
implementation of the presumptive standards in the November 2021 
proposal, unless the state plans require other sources to overperform 
to compensate for the less stringent RULOF standards or the EPA's 
geographical evaluation is national in scope and national emissions 
result in equivalent or greater emissions reductions, even taking into 
account RULOF. The EPA requests comments on whether and how to account 
for the potential application of RULOF in state plans in the IRA 
equivalency determination and whether it would be appropriate to 
conduct any evaluation without considering the application of RULOF.
    The EPA notes that nothing in the new CAA section 136 supersedes 
the EPA's statutory obligations under CAA section 111. The Methane 
Emission and Waste Reduction Incentive Program does not supersede the 
EPA's statutory obligation, under CAA section 111, to regulate methane 
emissions from the Crude Oil and Natural Gas source category. The EPA 
first regulated GHG emissions from new, reconstructed, and modified 
sources through limitations on methane emissions in its 2016 NSPS OOOOa 
rulemaking. Therefore, the Agency is obligated to review those 
standards at least every 8 years pursuant to CAA section 111(b)(1)(B). 
Moreover, CAA section 111(d) requires the EPA to establish emission 
guidelines to regulate methane emissions from any existing sources in 
the sector to which a standard of performance would apply if it were a 
new source. Although CAA section 136(f)(6) provides that facilities may 
be exempted from the obligation to pay methane charges if they are

[[Page 74722]]

compliant with applicable CAA section 111(b) and (d) standards meeting 
certain criteria after the Administrator makes the IRA equivalency 
determination in CAA section 136(f)(6)(A), CAA section 136 does not 
provide that the Methane Emission and Waste Reduction Incentive Program 
may, in the alternative, serve as a compliance alternative for any 
applicable CAA section 111 standards for methane. Accordingly, affected 
facilities subject to the final NSPS OOOOb must continue to comply with 
the final standards of performance regardless of whether they are 
subject to or exempted from the waste emissions charge. Likewise, 
designated facilities subject to standards of performance pursuant to 
either an approved state plan or a federal plan according to the 
requirements in CAA section 111(d) and the final EG OOOOc must continue 
to comply with those standards regardless of whether they are subject 
to or exempted from the waste emissions charge. The EPA acknowledges 
the potential interplay between the provisions in this proposed rule 
and the Methane Emissions and Waste Reduction Incentive Program and 
invites comment on approaches for examining the economic impacts of 
these programs individually and collectively.

IV. Summary and Rationale for Changes to the Proposed NSPS OOOOb and EG 
OOOOc

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

    As discussed in section XI.A of the November 2021 proposal preamble 
(86 FR 63169; November 15, 2021), fugitive emissions are unintended 
emissions that can occur from a range of components at any time. The 
magnitude of these emissions can also vary widely. The EPA has 
historically addressed fugitive emissions from the Crude Oil and 
Natural Gas source category through ground-based component level 
monitoring using OGI or Method 21 of appendix A-7 to 40 CFR part 60 
(EPA Method 21).
    This section presents a summary of the November 2021 proposal, the 
rationales for making certain changes to the proposed standards and 
requirements, and the resulting NSPS standards and EG presumptive 
standards the EPA is proposing via this supplemental proposal for 
fugitive emissions from well sites and compressor stations. For 
proposed standards and requirements that have not changed since the 
November 2021 proposal, their supporting rationales are not reiterated 
in this supplemental proposal. Rationale included in the November 2021 
proposal for these standards and requirements can be found in that 
proposal preamble (86 FR 63110; November 15, 2021) and in the technical 
support document (TSD) for the November 2021 proposal located at (EPA-
HQ-OAR-2017-0166).
1. Fugitive Emissions at Well Sites and Centralized Production 
Facilities
a. NSPS OOOOb
i. Summary of November 2021 Proposal
    Affected Facility. The November 2021 proposal defined the affected 
facility as the collection of fugitive emissions components located at 
well sites and centralized production facilities. The November 2021 
proposal excluded ``wellhead only well sites'' as affected facilities 
under NSPS OOOOb, which were defined as well sites with one or more 
wellheads and no major production and processing equipment. Major 
production and processing equipment was defined as reciprocating or 
centrifugal compressors, glycol dehydrators, heater/treaters, 
separators, and storage vessels.
    Definition of fugitive emissions component. The November 2021 
proposal included an expanded definition of fugitive emissions 
component that was intended to capture the known sources of large 
emission events. Specifically, the proposed definition in the November 
2021 proposal defined a fugitive emissions component 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, 
pressure relief devices, open-ended lines, flanges, all covers and CVS, 
all thief hatches or other openings on a controlled storage vessel, 
compressors, instruments, meters, natural gas-driven pneumatic 
controllers, or natural gas-driven pneumatic 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.'' (86 FR 63170; November 15, 2021).
    Summary of November 2021 Proposal BSER Analysis. The methodology 
used to determine BSER for the November 2021 proposal was presented in 
the section X.II.A of that proposal preamble (86 FR 63186; November 15, 
2021). In the November 2021 proposal, the EPA proposed new work 
practice standards for the collection of fugitive emissions components 
located at well sites. The EPA proposed that well sites with total 
site-level baseline methane emissions less than 3 tpy would 
demonstrate, based on a one-time site-specific survey, that actual 
emissions are reflected in the baseline methane emissions calculation. 
For well sites with total site-level baseline methane emissions of 3 
tpy or greater, the EPA proposed quarterly OGI or EPA Method 21 
monitoring. The EPA also co-proposed an alternative set of work 
practice standards: for well sites with total site-level baseline 
methane emissions of 3 tpy or greater and less than 8 tpy semiannual 
OGI or EPA Method 21 monitoring would apply; and for well sites with 
total site-level baseline methane emissions of 8 tpy or greater, 
quarterly OGI or EPA Method 21 monitoring would apply. For sites using 
OGI to detect fugitive emissions under any of these proposed work 
practice standards, the EPA proposed that surveys would be conducted 
according to the procedures proposed as appendix K. See section VI of 
this preamble for more information regarding appendix K.
ii. Changes to Proposal and Rationale
    The EPA is proposing certain changes to the November 2021 proposal 
standards for NSPS OOOOb. Specifically, the EPA is proposing: (1) To 
require OGI monitoring for well sites and centralized production 
facilities following the monitoring plan required in proposed 40 CFR 
60.5397b instead of requiring the procedures being proposed in appendix 
K for these sites; (2) to expand the affected facility definition to 
include wellhead only well sites, which were previously exempt, and add 
a subcategory for small well sites; (3) to revise the definition of 
fugitive emissions component; (4) to require periodic AVO or other 
detection methods for all well sites and centralized production 
facilities (except those located on the Alaskan North Slope) at 
frequencies based on the subcategory of well site; (5) to require 
periodic OGI fugitive emissions monitoring based on the number and type 
of equipment located at the well site, in lieu of the baseline 
emissions calculations required in the November 2021 proposal; and (6) 
to include requirements for well closures that would indicate when 
fugitive emissions monitoring could stop.
    Appendix K. The EPA is not including a requirement to conduct OGI

[[Page 74723]]

monitoring according to the proposed appendix K for well sites or 
centralized production facilities, as was proposed in the November 2021 
proposal. Instead, the EPA is proposing to require OGI surveys 
following the procedures specified in the proposed regulatory text for 
NSPS OOOOb (at 40 CFR 60.5397b) or according to EPA Method 21. The EPA 
received extensive comments \25\ from oil and gas operators and other 
groups on the numerous complexities associated with following the 
proposed appendix K, especially considering the remoteness and size of 
many of these sites. In addition, commenters pointed out that OGI has 
always been the BSER for fugitive monitoring at well sites and was 
never designed as a replacement for EPA Method 21, while appendix K was 
designed for use at more complex processing facilities that have 
historically been subject to monitoring following EPA Method 21. The 
EPA agrees with the commenters and is proposing requirements within 
NSPS OOOOb at 40 CFR 60.5397b in lieu of the procedures in appendix K 
for fugitive emissions monitoring at well sites or centralized 
production facilities. See section VI of this preamble for additional 
information on what the EPA is proposing for appendix K related to 
other sources (e.g., natural gas processing plants).
---------------------------------------------------------------------------

    \25\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0579, EPA-HQ-OAR-
2021-0317-0743, EPA-HQ-OAR-2021-0317-0764, EPA-HQ-OAR-2021-0317-
0777, EPA-HQ-OAR-2021-0317-0782, EPA-HQ-OAR-2021-0317-0786, EPA-HQ-
OAR-2021-0317-0793, EPA-HQ-OAR-2021-0317-0802, EPA-HQ-OAR-2021-0317-
0807, EPA-HQ-OAR-2021-0317-0808, EPA-HQ-OAR-2021-0317-0810, EPA-HQ-
OAR-2021-0317-0814, EPA-HQ-OAR-2021-0317-0817, EPA-HQ-OAR-2021-0317-
0820, EPA-HQ-OAR-2021-0317-0831, EPA-HQ-OAR-2021-0317-0834, and EPA-
HQ-OAR-2021-0317-0938.
---------------------------------------------------------------------------

    Affected facility and subcategorization of well sites. The EPA is 
proposing to expand the affected facility definition to include the 
collection of fugitive emissions components at all well sites, 
including the previously excluded wellhead only well sites. Various 
studies, including a recent U.S. Department of Energy funded study on 
quantifying methane emissions from marginal wells,\26\ demonstrate that 
fugitive emissions do occur from wellheads, and in some cases can be 
significant. As discussed in detail later in this section, the EPA 
evaluated emissions reductions resulting from the implementation of a 
fugitive emissions monitoring and repair program for a range of well 
site and centralized production facility configurations, ranging from 
the single wellhead only well site, to sites with specific major 
production and processing equipment present. While different types of 
monitoring techniques were found appropriate at the various site 
configurations evaluated, the EPA did not find support for an exemption 
of any site from the standards. Therefore, the EPA is proposing to 
define the affected facility as the collection of fugitive emissions 
components located at a well site or centralized production facility 
with no exemptions.
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    \26\ Bowers, Richard L. Quantification of Methane Emissions from 
Marginal (Low Production Rate) Oil and Natural Gas Wells. United 
States. https://doi.org/10.2172/1865859.
---------------------------------------------------------------------------

    Further, the EPA is proposing monitoring and repair programs 
specific to four distinct subcategories of well sites: (1) Single 
wellhead only well sites,\27\ (2) wellhead only well sites with two or 
more wellheads, (3) well sites and centralized production facilities 
\28\ with major production and processing equipment, and (4) small well 
sites. The third subcategory includes well sites and centralized 
production facilities that have: (1) One or more controlled storage 
vessels, (2) one or more control devices, (3) one or more natural gas-
driven pneumatic controllers or pumps, or (4) two or more other major 
production and processing equipment. The fourth subcategory, small well 
sites, are single wellhead well sites that do not contain any 
controlled storage vessels, control devices, pneumatic controller 
affected facilities, or pneumatic pump affected facilities, and include 
only one other piece of major production and processing equipment. 
Major production and processing equipment that would be allowed at a 
small well site would include a single separator, glycol dehydrator, 
centrifugal and reciprocating compressor,\29\ heater/treater, and 
storage vessel that is not controlled. By this definition, a small well 
site could only potentially contain a well affected facility (for well 
completion operations or gas well liquids unloading operations that do 
not utilize a CVS to route emissions to a control device) and a 
fugitive emissions components affected facility. No other affected 
facilities, including those utilizing CVS (such as pneumatic pumps 
routing to control) can be present for a well site to meet the 
definition of a small well site. The proposed monitoring requirements 
for each of these subcategories is described in more detail later in 
this section.
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    \27\ The EPA defines a wellhead only well site as a well site 
that contains one or more wellheads and no major production and 
processing equipment.
    \28\ Centralized production facilities include one or more 
storage vessels and all equipment at a single surface site used to 
gather, for the purpose of sale or processing to sell, crude oil, 
condensate, produced water, or intermediate hydrocarbon liquid from 
one or more offsite natural gas or oil production wells. This 
equipment includes, but is not limited to, equipment used for 
storage, separation, treating, dehydration, artificial lift, 
combustion, compression, pumping, metering, monitoring, and 
flowline. Process vessels and process tanks are not considered 
storage vessels or storage tanks. A centralized production facility 
is located upstream of the natural gas processing plant or the crude 
oil pipeline breakout station and is a part of producing operations.
    \29\ The EPA is proposing to exclude compressors that are 
located at well sites from the definition of a centrifugal affected 
facility and reciprocating affected facility, consistent with the 
November 2021 proposal. See 86 FR 63180 (November 15, 2021).
---------------------------------------------------------------------------

    Definition of fugitive emissions component. The EPA is proposing 
specific revisions to the definition of fugitive emissions component 
that was included in the November 2021 proposal. First, the EPA is 
proposing to add yard piping as one of the specifically enumerated 
components in the definition of a fugitive emissions component. While 
not common, pipes can experience cracks or holes, which can lead to 
fugitive emissions. The EPA is proposing to include yard piping in the 
definition of fugitive emissions component to ensure that when fugitive 
emissions are found from the pipe itself the necessary repairs are 
completed accordingly.
    Second, the EPA is correcting an error made in the November 2021 
proposal. The EPA had proposed that all thief hatches and other 
openings on all controlled storage vessels would be considered fugitive 
emissions components. This definition inadvertently included storage 
vessels that would already be subject to control as storage vessel 
affected facilities/designated facilities, including regular 
inspections of thief hatches and other sources of fugitive emissions 
that are separately required as part of the proposed standards for 
storage vessel affected facilities/designated facilities (see section 
IV.I of this preamble). The EPA is correcting that error in this 
supplemental proposal to avoid establishing redundant or duplicative 
requirements. Instead, the EPA is defining fugitive emissions 
components to include all thief hatches and other openings on storage 
vessels that are constructed, reconstructed, or modified after November 
15, 2021, and not also subject to control as storage vessel affected 
facilities. This would include thief hatches and other openings on both 
uncontrolled storage vessels and storage vessels that are controlled 
for other purposes but not subject to NSPS OOOOb control requirements 
because fugitive emissions can occur from these components.
    Third, the EPA is not defining control devices as fugitive 
emissions

[[Page 74724]]

components. One commenter stated that emissions resulting from 
noncompliance with control device requirements should not also be 
defined as fugitive emissions.\30\ This commenter opined that since 
control devices are inherently designed to have emissions, even when 
well operated, it should be expected that some amount of methane and 
VOC would be detected during an OGI survey for fugitive emissions. The 
EPA agrees that control devices should not be treated as fugitive 
emissions components and is therefore revising the definition in this 
proposal to not include those devices. Further, as discussed in more 
detail in section IV.H of this preamble, the EPA anticipates that 
control devices are used to meet at least one of the emissions 
standards in the proposed rules, and as such, they would be subject to 
the control device requirements in NSPS OOOOb or EG OOOOc. See section 
IV.H of this preamble for additional discussion on proposed 
requirements specific to control devices.
---------------------------------------------------------------------------

    \30\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.
---------------------------------------------------------------------------

    Finally, the EPA is not maintaining the inclusion of natural gas-
driven pneumatic controllers or natural gas-driven pneumatic pumps as 
fugitive emissions components. These devices are both separate affected 
facilities with separate standards identified as BSER.\31\ See sections 
IV.D and IV.E of this preamble for information about the proposed BSER 
for natural gas-driven pneumatic controllers and natural gas-driven 
pneumatic pumps, respectively.
---------------------------------------------------------------------------

    \31\ As explained in sections IV.D for pneumatic controllers and 
IV.E for pneumatic pumps, only natural gas-driven pneumatic 
controllers and pumps are defined as affected facilities. For a 
controller or pump to not be an affected facility, it would need to 
be electric or solar, which would not have the potential to emit 
methane or VOC emissions. Therefore, the EPA does not consider 
pneumatic controllers or pneumatic pumps part of the fugitive 
emissions components when they are not affected facilities as 
controllers or pumps.
---------------------------------------------------------------------------

    The EPA is proposing specific requirements throughout this 
supplemental proposal that will address emissions from controlled 
storage vessels and natural gas-driven pneumatic controllers and pumps, 
including requirements for quarterly OGI monitoring. These monitoring 
requirements provide compliance assurance that the proposed performance 
standards for these sources are being complied with and obviate any 
need to include these sources in the definition of a fugitive emissions 
component. For control devices, the EPA is proposing additional initial 
and continuous compliance measures to ensure the required emissions 
reductions are being achieved. See sections IV.D for discussion on 
pneumatic controllers, IV.E for discussion on pneumatic pumps, IV.H for 
discussion on combustion control devices, IV.J for discussion on 
storage vessels, and IV.K for discussion on covers and CVS.\32\
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    \32\ The EPA notes quarterly OGI monitoring will also be 
performed to demonstrate compliance with specific standards for 
controlled storage vessels, natural gas-driven pneumatic 
controllers, natural gas-driven pneumatic pumps, and CVS associated 
with any affected facilities at well sites. This quarterly OGI 
monitoring would take place during the same quarterly OGI monitoring 
of the fugitive emissions components affected facility located at 
the same well site.
---------------------------------------------------------------------------

    Comments received on monitoring requirements. As discussed in the 
November 2021 proposal, the EPA proposed to require fugitive emissions 
monitoring using OGI based on the site-level methane baseline 
emissions, as determined, in part, through equipment and component 
count emissions factors. Further, the EPA solicited comment on adding 
routine AVO monitoring in addition to periodic OGI monitoring to help 
identify potential large emission events. Several comments, mostly from 
small businesses, were received regarding the use of AVO inspections 
because these are low cost and simple inspections that would identify 
indications of leaks, such as open thief hatches on storage vessels. 
These comments ranged from requiring monthly to annual AVO inspections 
in lieu of OGI monitoring, to requests to minimize the complexity of 
any associated recordkeeping and reporting requirements should the EPA 
require this type of inspection.\33\
---------------------------------------------------------------------------

    \33\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0585, EPA-HQ-OAR-
2021-0317-0814, EPA-HQ-OAR-2021-0317-0822, EPA-HQ-OAR-2021-0317-
0929, and EPA-HQ-OAR-2021-0317-0935.
---------------------------------------------------------------------------

    The EPA received substantive comments from several commenters on 
the November 2021 proposal regarding OGI monitoring arguing that the 
proposed requirements for well sites were unreasonable and would be 
difficult to implement, especially for well sites with total site-level 
baseline methane emissions less than 3 tpy. Specifically, these 
commenters \34\ asserted that there would be challenges around 
calculating the site-level baseline emissions and that this task would 
be burdensome, while other commenters \35\ asserted the calculations 
would result in no regular monitoring at sites that have leak-prone 
equipment. Further, commenters noted that it would be difficult to 
verify the emissions calculations, which could result in compliance 
and/or enforcement challenges. According to industry commenters,\36\ 
the requirement to repeat the calculation when equipment is added or 
removed from the site would be especially burdensome. One of the 
commenters further stated this requirement would force owners and 
operators to constantly maintain an inventory of equipment, with some 
operators carrying this burden for hundreds to thousands of sites.\37\ 
Moreover, the commenter indicated that the EPA has not explained the 
need for the proposed recalculation of site-level methane emissions 
based on equipment changes and how this would have an environmental 
benefit. Another commenter argued that the EPA did not properly explain 
the basis for the emissions thresholds and disagreed with the 
components and equipment included in the calculation, as well as the 
use of the GHGRP emissions factors.\38\
---------------------------------------------------------------------------

    \34\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0808 and EPA-HQ-
OAR-2021-0317-0814.
    \35\ See Document ID No. EPA-HQ-OAR-2021-0317-0844.
    \36\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0808 and EPA-HQ-
OAR-2021-0317-0814.
    \37\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.
    \38\ See Document ID No. EPA-HQ-OAR-2021-0317-0814.
---------------------------------------------------------------------------

    In response to the proposed site-specific survey to demonstrate 
that actual emissions are reflected in the baseline emissions 
calculation, some commenters asserted that well sites with emissions 
less than 3 tpy should not be exempt from regular monitoring. According 
to commenters, even small sites can have leaks with significant 
emissions.\39\ For this reason, the commenters made the case that 
regular monitoring should be required for all sites. Some commenters 
also expressed that the requirement to calculate site-level methane 
baseline emissions and conduct an initial survey was confusing. As 
explained by one commenter, ``[the] EPA states well sites with site-
level baseline methane emissions [less than] 3 tpy are not required to 
conduct OGI monitoring.'' \40\ See 86 FR 63171 (November 15, 2021); 
however, since the EPA also proposed that well sites would be required 
to perform a survey to confirm that the actual emissions are less than 
3 tpy, the commenter viewed this as a contradiction within the rule, 
thus making it unclear what the EPA was proposing.
---------------------------------------------------------------------------

    \39\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0568, EPA-HQ-OAR-
2021-0317-0769, EPA-HQ-OAR-2021-0317-0844, and EPA-HQ-OAR-2021-0317-
1267.
    \40\ See Document ID No. EPA-HQ-OAR-2021-0317-0727.
---------------------------------------------------------------------------

    One commenter indicated that monitoring should also be required for

[[Page 74725]]

wellhead only well sites because, even though less equipment (and so 
fewer components) is present at a wellhead only well site, the wellhead 
itself is a source of emissions, which should be inspected for fugitive 
emissions.\41\ Other commenters provided similar comments and urged the 
EPA to remove the exemption for wellhead only well sites because these 
well sites have other smaller equipment that leaks and 
malfunctions,\42\ with large emissions having been observed from these 
sites,\43\ even though these sites do not have major production and 
processing equipment. Further, commenters noted that well sites with 
equipment with potentially significant emissions should not be 
considered a wellhead only well site or excluded from regular 
monitoring. The commenter urged the EPA that, if the wellhead only well 
site exemption is retained, it must only apply to single wellhead 
sites. Even if no associated equipment is located at a wellhead only 
well site, sites with multiple wellheads can have a number of 
components and subsequently potential sources of fugitive 
emissions.\44\ This same commenter, who opposes the 3 tpy threshold, 
noted that ``failure prone equipment'' such as storage vessels, 
separators, flares, and natural gas-driven pneumatic controllers often 
operate incorrectly and can cause significant emissions.\45\ This 
commenter argued that sites with this type of equipment should be 
required to monitor on a frequent basis.
---------------------------------------------------------------------------

    \41\ See Document ID No. EPA-HQ-OAR-2021-0317-0769.
    \42\ See Document ID No. EPA-HQ-OAR-2021-0317-0586.
    \43\ See Document ID No. EPA-HQ-OAR-2021-0317-0844.
    \44\ Id.
    \45\ Id.
---------------------------------------------------------------------------

    Another commenter noted that the one-time survey for sites less 
than 3 tpy does not address the problem of future leaks or 
malfunctions.\46\ The commenter indicated that malfunctions account for 
a large amount of methane emissions and the commenter, therefore, 
recommended at least annual monitoring. Comments urging the EPA to 
exempt small, low producing wells were also received.\47\ Specifically, 
one commenter argued that low producing wells are not 
disproportionately large emitters.\48\ This commenter asked that the 
EPA exempt these wells, asserting that these sources can least afford 
monitoring and have relatively small emissions. The commenter further 
asked that the rule exempt wells defined by states as stripper wells.
---------------------------------------------------------------------------

    \46\ See Document ID No. EPA-HQ-OAR-2021-0317-1267.
    \47\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0425 and EPA-HQ-
OAR-2021-0317-0814.
    \48\ See Document ID No. EPA-HQ-OAR-2021-0317-0425.
---------------------------------------------------------------------------

    As illustrated by the comments, which specifically highlight many 
potential challenges related to implementation, compliance assurance, 
and efficacy in reducing emissions, the EPA agrees that the fugitive 
emissions monitoring program that was proposed in the November 2021 
proposal should be clarified and improved in order to address the 
issues identified by the various commenters. As explained below, after 
considering the comments, additional data, and a revised analysis, the 
EPA is proposing revised fugitive emissions applicability criteria, 
monitoring frequencies, and detection methods at well sites and 
centralized production facilities.
    Fugitive emissions monitoring and repair modeling. In the November 
2021 proposal, the EPA also solicited comment on other thresholds that 
could be used to set monitoring requirements for well sites, in lieu of 
using self-reported baseline emissions as a threshold. One of these 
options included an equipment-based approach, in which well sites with 
specific leak-prone equipment would have one set of requirements, while 
well sites with other equipment (or that lack leak-prone equipment) 
would have a different set of requirements. In comparison to a self-
reported baseline emissions threshold, such an approach would ensure 
routine OGI monitoring takes place at sites that have equipment that is 
most likely to have fugitive emissions more frequently, while also 
being more straightforward for owners and operators to implement and 
for the EPA and state regulators to verify and enforce. The EPA 
received feedback and additional information in response to this 
solicitation and used that information to develop a new analysis based 
on this equipment-based concept.
    To evaluate an equipment-based program, the EPA developed three 
distinct model plants. These model plants were designed to account for 
various equipment types located at sites and ranged from single 
wellhead only well sites to complex sites with various known sources of 
large emissions present. Specifically, these model plants include: (1) 
Single wellhead only well sites,\49\ (2) wellhead only well sites with 
two or more wellheads, and (3) well sites or centralized production 
facilities \50\ with major production and processing equipment. For the 
reasons explained later in this section, the EPA finds that small well 
sites have component counts, and thus emissions distributions, that are 
more comparable to single wellhead only well sites and less than multi-
wellhead only well sites. The EPA has not modeled this small well site 
subcategory. Fugitive emissions from small well sites would originate 
from the same types of components (e.g., valves, connectors, open-ended 
lines, or pressure relief devices) modeled with emissions for single 
wellhead only well sites, and the available data suggests that the 
single piece of equipment at the site would be of smaller size, and 
thus have fewer individual components, than those summarized for well 
sites and centralized production facilities with major production and 
processing equipment. However, for purposes of summarizing the 
component counts, the EPA is including small well sites in Table 7 
along with the details of the number and type of equipment included in 
each of the model plants used for emissions modeling. The EPA finds 
that evaluating several types of model plants based on equipment and 
component counts is consistent with the empirical literature on 
fugitive emissions, including the conclusion from the U.S. Department 
of Energy's (DOE) recent marginal well study that a strong correlation 
was observed between the major equipment count and the frequency of 
fugitive emissions.51 52 The

[[Page 74726]]

EPA is soliciting comment on the proposed model plants described in 
Table 7. The EPA is also seeking information on how to refine its 
approach to modeling fugitive emissions in the model plants developed 
for this analysis.
---------------------------------------------------------------------------

    \49\ The EPA defines a wellhead only well site as a well site 
that contains one or more wellheads and no major production and 
processing equipment. Major production and processing equipment 
includes reciprocating or centrifugal compressors, glycol 
dehydrators, heater/treaters, separators, and storage vessels 
collecting crude oil, condensate, intermediate hydrocarbon liquids, 
or produced water. The EPA does not consider meters and yard piping 
as major production and processing equipment for purposes of 
determining if a well site is a wellhead only well site.
    \50\ Centralized production facilities include one or more 
storage vessels and all equipment at a single surface site used to 
gather, for the purpose of sale or processing to sell, crude oil, 
condensate, produced water, or intermediate hydrocarbon liquid from 
one or more offsite natural gas or oil production wells. This 
equipment includes, but is not limited to, equipment used for 
storage, separation, treating, dehydration, artificial lift, 
combustion, compression, pumping, metering, monitoring, and 
flowline. Process vessels and process tanks are not considered 
storage vessels or storage tanks. A centralized production facility 
is located upstream of the natural gas processing plant or the crude 
oil pipeline breakout station and is a part of producing operations.
    \51\ Bowers, Richard L. Quantification of Methane Emissions from 
Marginal (Low Production Rate) Oil and Natural Gas Wells. United 
States. https://doi.org/10.2172/1865859.
    \52\ The U.S. DOE marginal well study did not collect 
information on individual component counts on major equipment but 
did find a strong correlation to emissions based on the size of the 
site (defined by the major equipment count). Thus, the proposed 
definition of a small well site is limited to inclusion of a single 
piece of specific major production and processing equipment.

                                 Table 7--Well Site Model Plant Component Counts
----------------------------------------------------------------------------------------------------------------
                                                                 Number of components at well site
                                                 ---------------------------------------------------------------
  Major equipment at well site         Count                                        Open ended       Pressure
                                                      Valves        Connectors         lines       relief valves
----------------------------------------------------------------------------------------------------------------
                                         Single Wellhead Only Well Sites
----------------------------------------------------------------------------------------------------------------
Gas Wellheads...................               1              10              38               1               0
Meter/Piping....................               1              13              48               1               1
                                 -------------------------------------------------------------------------------
    Total # of Components:......                                        112
----------------------------------------------------------------------------------------------------------------
                                                Small Well Sites
----------------------------------------------------------------------------------------------------------------
Gas Wellheads...................               1              10              38               1               0
Meter/Piping....................               1              13              48               1               1
Other Equipment \a\.............               1               9              34               1               1
                                 -------------------------------------------------------------------------------
    Total # of Components:......                                        157
----------------------------------------------------------------------------------------------------------------
                               Wellhead Only Well Sites with Two or More Wellheads
----------------------------------------------------------------------------------------------------------------
Gas Wellheads...................               2              19              75               2               0
Meter/Piping....................               2              26              96               1               1
                                 -------------------------------------------------------------------------------
    Total # of Components:......                                        220
----------------------------------------------------------------------------------------------------------------
         Well Sites and Centralized Production Facilities with Major Production and Processing Equipment
----------------------------------------------------------------------------------------------------------------
Gas Wellheads...................               2              19              75               2               0
Meter/Piping....................               2              26              96               1               1
Separators......................               2              44             137               8               3
In-Line Heaters.................               1              14              65               2               1
Dehydrators.....................               1              24              90               2               2
Storage Vessel Thief Hatch......               1               0               0               0               0
                                 -------------------------------------------------------------------------------
    Total # of Components:......                                        612
----------------------------------------------------------------------------------------------------------------
\a\ Major production and processing equipment that could be at a small well site includes compressors, glycol
  dehydrators, heater/treaters, separators, and uncontrolled storage vessels collecting crude oil, condensate,
  intermediate hydrocarbon liquids, or produced water. Small well sites cannot include one or more controlled
  storage vessels, control device, natural gas-driven pneumatic controllers, or natural gas-driven pneumatic
  pumps. The component counts provided in this table are based on the average number of valves identified in
  industry provided data for a small well site (34 valves) and assuming 3.8 connectors per valve, 1 open-ended
  line, and 1 pressure relief device consistent with component counts provided for other equipment.\53\

    In previous rulemakings, the EPA used component-level emissions 
factors that commenters on previous actions have stated are dated and 
not reflective of emissions detected through various recent measurement 
studies to determine baseline emissions and emissions reductions at 
various OGI monitoring frequencies.\54\ In contrast, several comments 
on the November 2021 proposal identified various modeling simulation 
tools that can be utilized for this same purpose and that build in 
emissions data from various emissions measurement campaigns providing 
empirical emissions data.
---------------------------------------------------------------------------

    \53\ See Document ID No. EPA-HQ-OAR-2017-0483-1006.
    \54\ See EPA Responses to Public Comments on Reconsideration of 
New Source Performance Standards (NSPS) Oil and Natural Gas Sector: 
Emission Standards for New, Reconstructed, and Modified Sources 
Reconsideration 40 CFR part 60, subpart OOOOa, located at Document 
ID No. EPA-HQ-OAR-2017-0483-2291.
---------------------------------------------------------------------------

    One such modeling simulation tool is the Fugitive Emissions 
Abatement Simulation Toolkit (FEAST). FEAST is an open-source modeling 
framework developed to evaluate the effectiveness of fugitive emissions 
programs at oil and gas facilities by simulating various scenarios of 
leaks (and subsequent repairs) occurring over time using an empirical 
leak dataset according to a randomized process. FEAST supports a 
variety of detection technologies, including OGI, aerial surveys, drone 
surveys, and continuous monitoring systems and can model hybrid 
programs (e.g., aerial surveys followed by ground-level OGI surveys). 
The effects of fugitive emissions monitoring and repair are simulated 
based on probability of detection (PoD) curves (or surfaces) for each 
monitoring method, which indicate the probability that a leak of a 
given size will be detected within a given survey (or time period for 
continuous monitoring technologies), and survey times (frequencies) are 
accounted for as finite time periods. The emissions present at the site 
during the modeled period of time are quantified, accounting for leak 
generation, identification, and repair, and emissions reductions can be 
calculated by comparing the simulated fugitive emissions program 
against a baseline scenario where no program is implemented.
    The EPA recognizes there are several options to identify fugitive 
emissions,

[[Page 74727]]

ranging from simple sensory methods to advanced detection technologies. 
The EPA solicited comment on the inclusion of simple AVO checks that 
could be performed in conjunction with periodic OGI monitoring surveys 
to identify large emissions between OGI monitoring surveys in the 
November 2021 proposal. The EPA maintains that it is imperative to 
ensure that well sites and centralized production facilities are 
operated in a manner such that emissions are minimized. Further, OGI or 
other detection technologies are not necessary for identifying fugitive 
emissions from certain fugitive emissions components, such as open 
thief hatches. Therefore, the EPA examined the use of regular AVO 
inspections to provide for potential additional emissions reductions 
associated with fugitive emissions components, and to compel operators 
to address issues whenever they find indications of a potential leak 
during regular visits to sites.
    One factor that can lead to fugitive emissions is a lack of 
maintenance, and it has been shown that when sites are not regularly 
visited, fugitive emissions can occur for long periods of time without 
any mitigation. For example, in comments provided on the October 15, 
2018 proposed reconsideration for NSPS OOOOa, it was reported that some 
sites can be operating in a state of disrepair, including rusty well 
shafts, broken valves, or fallen trees on equipment.\55\ While OGI and 
other monitoring technologies can be useful in identifying emissions 
from individual components, such as valves and connectors, these 
technologies require expensive equipment and specialized training of 
operators for identifying indications of fugitive emissions resulting 
from broken equipment or open thief hatches. On the other hand, AVO 
inspections are a useful tool for identifying when there are 
indications of a potential leak without the need for expensive 
equipment or specialized training of operators. For example, at sites 
that lack extensive background noise, a person would be able to hear if 
a high-pressure leak is present, which could present as a hissing 
sound. Field gas produced at well sites contains a mixture of methane 
and various VOCs, which have the potential to be detected by smell. 
Where the field gas contains a lot of condensate or other produced 
liquids, any resulting leaks would present as indications of liquids 
dripping or potentially puddles forming on the ground. In cold 
climates, ice formation on components could also indicate a potential 
leak. Finally, an open thief hatch on a storage vessel is easily 
identified with visual inspection.
---------------------------------------------------------------------------

    \55\ See Document ID No. EPA-HQ-OAR-2017-0483-2240.
---------------------------------------------------------------------------

    The EPA is proposing a revised approach to address fugitive 
emissions at well sites and centralized production facilities that 
establishes the monitoring frequency and detection method (AVO and/or 
OGI) based on results obtained from using FEAST \56\ to model various 
programs at the three model plants presented in this preamble. First, 
the EPA determined baseline methane emissions from each of the model 
plants using two leak generation rates, 0.5 and 1.0 percent. These leak 
generation rates represent the percentage of components leaking at any 
particular time at the site. The EPA chose these leak generation rates 
as a starting point for modeling to compare against measured emissions 
documented in credible empirical studies, such as the August 2021 paper 
by Rutherford, et al.\57\ This proposed approach is responsive to 
feedback from commenters indicating that the emissions factors we 
relied upon in the November 2021 proposal undercount fugitive 
emissions, and recommending that we utilize models based on recent 
measured data that is more representative of fugitive emissions in the 
field. The results of the FEAST simulations for AVO and OGI monitoring 
are presented in the remainder of this section for each of the model 
plants. For ground based OGI, the EPA used a minimum detection limit of 
60 g/hr consistent with the proposed camera specifications in 40 CFR 
60.5397b(c)(7)(i)(B) \58\ and assumed all leaks identified by OGI would 
be repaired within 30 days, consistent with the average repair time 
that would be required for fugitive emissions components.\59\ The 
results of these models provide an estimate of the number of leaks 
identified during an inspection and the potential emissions reductions, 
which the EPA then applied to its cost-effectiveness analysis to 
determine the BSER for each well site model plant. The EPA is seeking 
information on its estimates of repair costs associated with identified 
leaks.
---------------------------------------------------------------------------

    \56\ The EPA used FEAST version 3.1 to model the various 
programs. While the EPA used FEAST in this modeling exercise, the 
EPA would expect other available modeling simulation tools to 
produce similar results.
    \57\ Rutherford, J.S., Sherwin, E.D., Ravikumar, A.P. et al. 
Closing the methane gap in US oil and natural gas production 
emissions inventories. Nat Commun 12, 4715 (2021). https://doi.org/10.1038/s41467-021-25017-4.
    \58\ The EPA is adopting the same OGI camera specifications for 
fugitive emissions components as those in NSPS OOOOa.
    \59\ The EPA is proposing to require a first attempt at repair 
within 30 days of identifying fugitive emissions, with final repair 
required within 30 days of the first attempt.
---------------------------------------------------------------------------

    For purposes of evaluating the costs of the AVO inspections and OGI 
monitoring surveys, the EPA incorporated specific revisions into the 
cost analysis presented in the November 2021 proposal.\60\ The capital 
and annual costs associated with each type of inspection or monitoring 
program are presented in Tables 8 and 9.
---------------------------------------------------------------------------

    \60\ See November 2021 TSD for additional information on costs 
of OGI monitoring at Document ID No. EPA-HQ-OAR-2021-0317-0166.

   Table 8--Well Site Model Plant Costs Associated With OGI Monitoring
------------------------------------------------------------------------
            Description of item                       Costs ($)
------------------------------------------------------------------------
                    Capital Costs for OGI Inspections
------------------------------------------------------------------------
Read rule and instructions (per 22 well      $260.
 sites).
Develop monitoring plan (per 22 well sites)  $2,600.
Setup recordkeeping system (per well site).  $900.
------------------------------------------------------------------------
                Costs for OGI Inspections (per well site)
------------------------------------------------------------------------
OGI surveys................................  $142/hr.
Repairs....................................  $146 to $330/yr.
Resurvey...................................  $3 to $20/yr.
Annual licensing fees of recordkeeping       $870/yr.
 system.
Annual administrative costs for              $325/yr.
 recordkeeping/data management.

[[Page 74728]]

 
Prepare and submit information in annual     $195/yr.
 report.
------------------------------------------------------------------------

  Table 9--Well Site Model Plant Costs Associated With AVO Inspections
                       (Assumes No OGI Monitoring)
------------------------------------------------------------------------
            Description of item                       Costs ($)
------------------------------------------------------------------------
                    Capital Costs for AVO Inspections
------------------------------------------------------------------------
Read rule and instructions (per 22 well      $260.
 sites).
Develop monitoring plan (per 22 well sites)  $260.
Setup recordkeeping system (per well site).  $65.
------------------------------------------------------------------------
                Costs for AVO Inspections (per well site)
------------------------------------------------------------------------
AVO inspection, including preparation and    $65/hr.
 documentation.
Repairs....................................  $89/yr to $178/yr.
Resurvey...................................  $5/yr to $11/yr.
Prepare and submit information in annual     $65/yr.
 report.
------------------------------------------------------------------------

    For OGI monitoring at well sites, the capital costs presented in 
Table 8 remain unchanged from the November 2021 proposal. The capital 
costs associated with the fugitive emissions program are expected to be 
the same for each model plant because these capital costs include the 
cost of developing a fugitive emission monitoring plan and purchasing 
or developing a recordkeeping data management system specific to 
fugitive emissions monitoring and repair. More discussion about the 
capital costs, which remain unchanged in this proposal, can be found in 
section XII.A.1.a of the November 2021 proposal (86 FR 63189; November 
15, 2021).
    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 for OGI monitoring were mostly retained and 
consistent with the November 2021 proposal. However, the EPA 
incorporated the results of FEAST modeling for the newly developed 
model plants to include the modeled number of components identified as 
leaking, thus requiring repairs.\61\ Even though the leak generation 
rate used in the FEAST model was set to 0.5 and 1.0 percent for 
purposes of emissions reduction analyses, the empirical dataset used 
includes all leaks measured across numerous studies, many of which are 
below the expected mass detection limit of OGI cameras. As such, only a 
portion of the leaks generated are identified and repaired via the OGI 
monitoring program (approximately 57 percent in this analysis). 
Specifically, the estimated annual number of components requiring 
repair resulting from an OGI survey, as modeled by FEAST, were 0.62 for 
single wellhead only and small well sites, 1.25 for multi-wellhead only 
well sites, and 3.7 for well sites and centralized production 
facilities with major production and processing equipment. The EPA 
utilized the same repair costs and resurvey costs as in the November 
2021 proposal for OGI monitoring. All other inputs to the annual costs 
remain unchanged from the November 2021 proposal as well.
---------------------------------------------------------------------------

    \61\ Assumes an average of 0.62, 1.25, and 3.7 leaks found 
annually, for model plants 1-3, respectively.
---------------------------------------------------------------------------

    The estimated annual costs of the OGI-based fugitive emissions 
program at well sites and centralized production facilities range from 
$2,100 for annual monitoring to $6,000 for monthly monitoring for 
single wellhead only well sites. For multi-wellhead only well sites, 
the estimated annual costs of the fugitive emissions program range from 
$2,000 for annual monitoring to $5,900 for monthly monitoring. For well 
sites with major production and processing equipment, including those 
with controlled tanks, the estimated annual costs of the fugitive 
emissions program are estimated to range from $2,300 for annual 
monitoring to $7,000 for monthly monitoring. More detailed information 
on the capital and annual costs estimated for the fugitive emissions 
program can be found in the November 2021 TSD \62\ and in the 
Supplemental TSD for this action located at Docket ID No. EPA-HQ-OAR-
2021-0317.
---------------------------------------------------------------------------

    \62\ See Document ID No. EPA-HQ-OAR-2021-0317-0166.
---------------------------------------------------------------------------

    For this supplemental proposal, the EPA separately evaluated the 
costs associated with AVO monitoring. The EPA assumed capital and 
annual costs for each individual well site and evaluated the costs in 
two ways: (1) Assuming an operator visits the site at least as 
frequently as the inspection (no additional travel costs), and (2) 
assuming additional travel costs because the site is not visited at the 
same frequency as the inspection. When accounting for the second 
scenario, the EPA assumed a travel time of 1.25 hours round trip and 
applied the same hourly rate for operators as is used for the 
development of a monitoring plan and other actions. Further, the EPA 
assumes an inspection time ranging from 15 minutes (single wellhead 
only well sites) to 1 hour (centralized production facilities) to 
account for the added complexity at larger sites. The EPA also assumed 
1 repair per year for the single wellhead only, multi-wellhead only, 
and small well sites, and 2 repairs per year for larger well sites and 
centralized production facilities. While there is a lack of information 
on the emissions reductions achieved through an AVO inspection, the EPA 
is confident that specific indications of potential leaks (e.g., open 
valves or thief hatches) would be obvious to any operator performing 
these inspections and discusses these in more detail below for each 
model plant.
    The estimated annual costs of the AVO inspections at single 
wellhead only well sites and small well sites that are visited at least 
as frequently as the

[[Page 74729]]

AVO inspection frequency range from $214 for annual inspections to $660 
for monthly inspections. These estimates range from $300 for annual 
inspections to $1,630 for monthly inspections if additional travel 
costs are incorporated for these sites. For multi-wellhead only well 
sites, the estimated annual costs range from $265 for annual 
inspections to $1,150 for monthly inspections, and these costs range 
from $350 for annual inspections to $2,120 for monthly inspections when 
additional travel costs are added. For well sites with major production 
and processing equipment, the estimated annual costs range from $480 
for annual inspections to $2,650 for monthly inspections, and this 
range increases to $560 for annual inspections to $3,620 for monthly 
inspections when additional travel costs are incorporated. More 
detailed information on the capital and annual costs estimated for the 
AVO inspections can be found in the Supplemental TSD for this action 
located at Docket ID No. EPA-HQ-OAR-2021-0317. The EPA is soliciting 
comment on all aspects of the estimated costs of the AVO inspection 
program, including labor rates and the costs of repair.
    Single wellhead only well sites. The EPA has not previously defined 
single wellhead only well sites as fugitive emissions components 
affected facilities. For a single wellhead only well site, the most 
likely cause of emissions would be from an open valve allowing venting 
from the wellhead. In the U.S. DOE marginal well study, two of the top 
10 largest leaks found were located at the wellhead and were the result 
of an open valve on the well surface casing, which allowed venting to 
the atmosphere. These two sources resulted in emissions of 6.9 kg/hr 
methane (66 tpy) and 7.8 kg/hr methane (76 tpy).\63\ A third leak, also 
located at the wellhead, was identified as a hole in the side of the 
surface casing, resulting in emissions of 2.9 kg/hr methane (28 tpy) 
from this source. The other top 10 leak sources identified in the U.S. 
DOE marginal well study were on equipment that is not present at a 
single wellhead only well site (e.g., separators or storage vessels). 
The types of emissions sources located at the wellhead, including these 
large emissions sources found in the U.S. DOE marginal well study, can 
be easily identified using AVO inspections and would not require the 
use of OGI for identification. Therefore, the EPA evaluated a periodic 
AVO inspection and repair program for addressing fugitive emissions 
from single wellhead only well sites.
---------------------------------------------------------------------------

    \63\ Bowers, Richard L. Quantification of Methane Emissions from 
Marginal (Low Production Rate) Oil and Natural Gas Wells. United 
States. https://doi.org/10.2172/1865859. See Table 2 of the study 
for details on the top 10 emissions sources identified.
---------------------------------------------------------------------------

    First, the EPA modeled an AVO program at two leak generation rates 
(1.0 percent and 0.5 percent) to compare the resulting baseline methane 
emissions against empirical emissions data and identify which model 
results more closely reflect real-world emissions measurement campaign 
results. A comparison of the baseline methane emissions estimated at 
both of these leak generation rates to empirical data suggest that the 
0.5 percent leak generation rate is more likely to be indicative of the 
actual average emissions from single wellhead only well sites. Various 
studies indicate that, while these sites can occasionally experience 
large emissions events, such events are not as frequent as at more 
complex sites, and thus do not warrant application of a higher average 
emissions baseline for purposes of determining the BSER for these 
sites.\64\ The U.S. DOE marginal well study \65\ measured methane 
average population emissions ranging from 0.26 to 0.56 tpy from 
wellheads examined during the study, with negligible emissions reported 
from meters. Similarly, the 2021 Rutherford et al. study estimated an 
average emissions factor for a single wellhead of 3.4 kg/day (0.95 tpy) 
and a single meter of 2.7 kg/day (0.75 tpy) for a total of 1.70 tpy 
from a single wellhead only well site.\66\ Using the average emissions 
between these 2 studies, the baseline methane emissions are 1.13 tpy, 
which is consistent with the 0.5 percent leak generation rate results 
for our single wellhead only well sites, for which the FEAST model 
estimated a methane emissions baseline of 1.27 tpy (see Table 8). By 
contrast, the 1.0 percent leak generation rate baseline (2.97 tpy) is 
more than five times higher than the high end of the U.S. DOE marginal 
well study and 50 percent higher than the estimates from the 
Rutherford, et al. study. Therefore, the EPA is evaluating the cost of 
control for AVO inspections based on the modeled results for a 0.5 
percent leak generation rate at single wellhead only well sites. 
Additional details of the model results, including those for the 1.0 
percent leak generation rate, are included in the Supplemental TSD for 
this action located at Docket ID No. EPA-HQ-OAR-2021-0317.
---------------------------------------------------------------------------

    \64\ See https://pubs.acs.org/doi/10.1021/acs.est.0c02927, 
https://data.permianmap.org/pages/flaring, and https://www.edf.org/sites/default/files/documents/PermianMapMethodology_1.pdf.
    \65\ Bowers, Richard L. Quantification of Methane Emissions from 
Marginal (Low Production Rate) Oil and Natural Gas Wells. United 
States. https://doi.org/10.2172/1865859. Marginal wells are defined 
in this study as producing less than 15 barrels of oil equivalent 
per day (boe/day) of combined oil and natural gas.
    \66\ Rutherford, J.S., Sherwin, E.D., Ravikumar, A.P. et al. 
Closing the methane gap in US oil and natural gas production 
emissions inventories. Nat Commun 12, 4715 (2021). https://doi.org/10.1038/s41467-021-25017-4.

                  Table 10--Summary of Emissions Reductions and Cost-Effectiveness: AVO Inspections at Single Wellhead Only Well Sites
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                         Cost-effectiveness         Incremental cost-
                                                                              Methane        VOC     --------------------------       effectiveness
                     Monitoring frequency                      Annual cost    emission     emission                            -------------------------
                                                               ($/yr/site)   reduction    reduction   Methane ($/  VOC ($/ton)  Methane ($/
                                                                             (tpy/site)   (tpy/site)      ton)                      ton)     VOC ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                 Single Wellhead Well Sites: Includes additional travel costs Single Pollutant Approach
--------------------------------------------------------------------------------------------------------------------------------------------------------
Annual.......................................................         $296         0.11         0.03       $2,579       $9,278
Semiannual...................................................          417         0.40         0.11        1,048        3,769         $429       $1,543
Quarterly....................................................          660         0.56         0.16        1,181        4,249        1,511        5,436
Bimonthly....................................................          904         0.63         0.17        1,443        5,190        3,618       13,017
Monthly......................................................        1,633         0.69         0.19        2,367        8,515       11,455       41,208
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                  Single Wellhead Well Sites: Includes additional travel costs Multipollutant Approach
--------------------------------------------------------------------------------------------------------------------------------------------------------
Annual.......................................................          296         0.11         0.03        1,289        4,639

[[Page 74730]]

 
Semiannual...................................................          417         0.40         0.11          524        1,885          214          771
Quarterly....................................................          660         0.56         0.16          591        2,124          756        2,718
Bimonthly....................................................          904         0.63         0.17          721        2,595        1,809        6,509
Monthly......................................................        1,633         0.69         0.19        1,183        4,257        5,727       20,604
--------------------------------------------------------------------------------------------------------------------------------------------------------

    It is the EPA's understanding that single wellhead only well sites 
are not regularly visited. Instead, these sites are expected to only be 
visited when specific operations are necessary that require the 
presence of an operator on the site (e.g., well workovers). Thus, the 
EPA finds it more appropriate to base decisions related to whether an 
AVO inspection frequency is reasonable on the analysis that includes 
additional travel costs to the site. Based on the information 
summarized in Table 10, which include additional travel costs, under 
the single pollutant approach where all costs are assigned to methane 
and zero cost to VOC, the semiannual, quarterly, and bimonthly (i.e., 
every other month) frequencies are reasonable for methane emissions; 
similarly, where all costs are assigned to VOC and zero cost to 
methane, the semiannual, quarterly, and bimonthly frequencies are 
reasonable for VOC emissions. Under the multipollutant approach where 
the costs are divided equally between the two pollutants, all of the 
frequencies appear reasonable, including monthly monitoring.
    The EPA next evaluated the incremental cost associated with 
advancing to each more frequent monitoring schedule to determine which 
frequencies would be reasonable for AVO inspections. As shown in Table 
10 where additional travel costs are included, the incremental cost of 
going from semiannual to quarterly inspections is reasonable under both 
the single pollutant approach (for both methane and VOC individually) 
and the multipollutant approach. Under the single pollutant approach, 
the incremental cost of going from quarterly to bimonthly is not 
reasonable for either methane or VOC emissions. Under the 
multipollutant approach, the incremental cost of going from quarterly 
to bimonthly is not reasonable for VOC ($6,500/ton VOC), which means it 
is not cost-effective under the multipollutant approach. Therefore, the 
EPA finds it is not reasonable to require bimonthly AVO inspections.
    In summary, the EPA finds that the BSER for single wellhead only 
well sites is quarterly AVO inspections for indications of potential 
leaks, with specific attention given to ensuring surface casing valves 
are closed to prevent the venting of emissions. The EPA is soliciting 
comment and additional data related to the costs and other potential 
causes of emissions on a single wellhead that could easily be 
identified using AVO inspections.
    Small well sites. As stated in the November 2021 proposal, the EPA 
remains mindful about how the fugitive emissions monitoring 
requirements will affect small businesses. The EPA solicited comment in 
the November 2021 proposal on regulatory alternatives and additional 
information that would warrant considering a subset of sites 
differently based on a potentially different emissions profile, 
production levels, equipment onsite, or other factors. (86 FR 63173; 
November 15, 2021). The EPA examined data provided through an 
information collection request (ICR) distributed in 2016, data provided 
on equipment/component counts in relation to the October 15, 2018, 
proposed reconsideration of NSPS OOOOa from independent producers (many 
of whom are small businesses), data provided through comments on the 
November 2021 proposal from independent producers, and data contained 
in the U.S. DOE marginal well study to determine if a subset of well 
sites with major production and processing equipment should be 
considered differently.
    Consistent with comments received on previous rulemakings, the EPA 
received comments on the November 2021 proposal requesting 
consideration of production volumes as a factor when establishing the 
BSER for well sites.\67\ One commenter stated that the EPA has 
emphasized component counts instead of considering the significantly 
more important role that production rates and operating pressure play 
on the amount of fugitive emissions.\68\ This commenter then referenced 
the U.S. DOE marginal well study as showing that most low production 
well sites (many of which are owned or operated by small businesses) 
emit less than 3 tpy of methane. However, that marginal well study 
concludes that the frequency and magnitude of emissions from well sites 
are more strongly correlated with equipment counts, not production 
rates.\69\ Further, this study broke down emissions by site size and 
production levels and found that the smallest emissions rates were from 
the second production level bin (2 barrels of oil equivalent per day 
(boe/day) to 6 boe/day) and not the sites with production less than 2 
boe/day. Another study issued in April 2022 by Omara, et al. concludes 
that approximately half of the methane emissions emitted from well 
sites in the U.S. comes from low production well sites (15 boe/day or 
less production rates).70 71 However, the EPA notes that 
this study is not limited to

[[Page 74731]]

fugitive emissions, and the overall impacts on emissions reductions 
achieved if these rules are finalized as proposed, would target the 
emissions reported in that study as a whole. Therefore, the EPA does 
not have compelling information that suggests production levels should 
provide the basis for consideration of different fugitive emissions 
requirements for well sites.
---------------------------------------------------------------------------

    \67\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0425 and EPA-HQ-
OAR-2021-0317-0814.
    \68\ See Document ID No. EPA-HQ-OAR-2021-0317-0814.
    \69\ Section 5.2.1 of the study concludes, ``The correlation 
between major equipment counts and site emission frequency 
(expressed as the number of detected emissions per piece of major 
equipment, i.e., not absolute count of emissions), was strong with 
the categorical site `size' variable and moderate (positive) with 
the numeric equipment count. Among evaluated numeric variables, site 
equipment counts also exhibited the strongest associations with both 
frequency and magnitude of sitewide emissions, exhibiting only a 
moderate positive correlation with detection frequency and weak 
associations with whole gas and methane emission rates. Weak 
correlations were also consistently detected among both the 
frequency and magnitude of emissions, total oil and gas production, 
and gas production rates.'' See Bowers, Richard L. Quantification of 
Methane Emissions from Marginal (Low Production Rate) Oil and 
Natural Gas Wells. United States. https://doi.org/10.2172/1865859. 
page 19.
    \70\ Omara, M., Zavala-Araiza, D., Lyon, D.R. et al. Methane 
emissions from US low production oil and natural gas well sites. Nat 
Commun 13, 2085 (2022). https://doi.org/10.1038/s41467-022-29709-3.
    \71\ The EPA notes that Omara et al. analyzed data from offsite 
measurements of methane emissions from well sites. These 
measurements would include methane from any leak, venting, flaring, 
or other source onsite and, therefore, conclusions from this study 
cannot be directly applied to the specific fugitive sources covered 
by this action.
---------------------------------------------------------------------------

    While the EPA does not find that production rates correlate to the 
amount of fugitive emissions and therefore should not be used as a 
basis for establishing different fugitive emissions monitoring 
requirements among well sites, we do find that the empirical data 
described supports distinguishing among well sites based on equipment 
and component counts. As explained earlier in this section, the EPA 
utilized model plants, with different equipment and component counts to 
differentiate fugitive emissions monitoring programs using AVO and OGI 
through FEAST modeling simulations.
    Based on comments received on the October 15, 2018, reconsideration 
proposal, the EPA has evaluated if certain well sites with major 
production and processing equipment are more comparable in total 
component counts to either of the wellhead only model plants. For 
example, one commenter in 2018 provided average equipment and/or 
component counts for sites in various states that are owned and 
operated by independent producers, many of whom are small businesses. 
These counts included the number of storage vessels, wellheads, and 
valves, specifically.\72\ That information suggests that there are well 
sites owned and operated by small businesses that are predominantly 
composed of single wellheads, with 1 to 2 storage vessels and 11 to 53 
valves. These component counts are significantly lower than those 
estimated for the model plants developed for this supplemental proposal 
that include major production and processing equipment, which include 
127 total valves. This suggests that certain well sites are smaller 
than our model facilities, and that as a result the model may overstate 
emissions reductions, and thus cost-effectiveness, for fugitive 
emissions programs at such small sites. In fact, the EPA anticipates 
that there are well sites with major production and processing 
equipment that are of similar component counts as the single wellhead 
only well site (total components equal to 112, with 23 total valves). 
Therefore, the EPA does find that a separate BSER determination is 
warranted for certain small sites.
---------------------------------------------------------------------------

    \72\ See Document ID No. EPA-HQ-OAR-2017-0483-1006.
---------------------------------------------------------------------------

    The EPA is proposing to define a small well site, for purposes of 
the fugitive emissions monitoring requirements, as a well site that 
contains a single wellhead, no more than one piece of certain major 
production and processing equipment, and associated meters and yard 
piping. The major production and processing equipment could include a 
single separator, glycol dehydrator, heater/treater, compressor,\73\ or 
uncontrolled storage vessel. It cannot include controlled storage 
vessels, control devices, or natural gas-driven pneumatic controllers, 
as those are known to be sources of large emissions events. Further, 
the equipment allowed at these small sites would not include any 
affected/designated facilities, nor would it include a CVS which is 
subject to quarterly OGI monitoring as explained in section IV.K. The 
EPA is proposing this narrow definition to ensure that sites with leak-
prone equipment that requires OGI (or other advanced technology) 
monitoring are not present at the site. Based on the EPA's analysis of 
data collected from an ICR distributed in 2016 and applied to the 
universe of wells operating in 2019, it is estimated that approximately 
95,000 well sites would meet this definition (nationwide), or 
approximately 12 percent of the total nationwide well site count.
---------------------------------------------------------------------------

    \73\ The EPA has proposed to exclude compressors located at well 
sites from being affected facilities because these are generally 
small compressors that do not have significant emissions. 
Compressors have been excluded from being affected facilities in 
NSPS OOOO and NSPS OOOOa as well.
---------------------------------------------------------------------------

    Surface casing valves and thief hatches on an uncontrolled storage 
vessel are the most likely emissions sources for these small well 
sites. As discussed for single wellhead only well sites, the surface 
casing valve can easily be identified as open or closed during an AVO 
inspection and would not require the use of OGI to detect the leak. 
Similarly, the use of OGI is not necessary to be able to identify if a 
thief hatch is not closed. For example, the hatch may be fully open, 
left unlatched and ``chattering'' with fluctuations from the storage 
vessel pressures, or have visible indications of liquids such as 
staining around the hatch. Therefore, the EPA has evaluated AVO 
inspections to determine the BSER for small well sites.
    The EPA utilized the same model results as those provided for 
single wellhead only well sites. For that model plant, the baseline 
methane emissions were estimated at 1.27 tpy. In the U.S. DOE marginal 
well study, the average methane emissions rate for a thief hatch was 
0.20 tpy. Likewise, the emissions factor for tank leaks identified in 
Rutherford, et al. was 0.195 tpy (0.7 kg/day). Therefore, the EPA finds 
it appropriate to utilize the same model results as those presented in 
Table 10 for single wellhead only sites to determine the BSER for small 
well sites. Based on the information presented in Table 10, and our 
conclusions on the cost-effectiveness of the options for single 
wellhead only well sites, the EPA proposes quarterly AVO inspections 
for monitoring fugitive emissions at small well sites.
    Additionally, for thief hatches and other openings on storage 
vessels that are proposed as fugitive emissions components, the EPA is 
proposing to require an equipment standard as part of the fugitive 
emissions work practice that requires these thief hatches to remain 
closed and sealed at all times except during sampling, adding process 
material, or attended maintenance operations.\74\ This type of 
equipment standard has been used in other leak detection work practices 
where open-ended lines and valves are required to be equipped with a 
closure device (e.g., cap or plug) to seal the open-end of the line or 
valve, thus preventing leaks from going to the atmosphere. An open 
thief hatch, even on an uncontrolled storage vessel, would still 
contribute fugitive emissions and maintaining the thief hatch in a 
closed position will provide for reduction of emissions at no 
additional cost. Further, one commenter provided a recommendation that 
the EPA should propose requirements to maintain thief hatches closed 
and sealed until the potential emissions from a tank battery exceeds 
the applicability threshold requiring controls for storage vessels and 
that AVO monitoring should be used to verify compliance with this 
standard.\75\ The EPA agrees with this recommendation that AVO 
inspections would be appropriate to verify compliance with the proposed 
``closed and sealed'' requirement, and therefore, is proposing this 
requirement for thief hatches that are fugitive emissions components.
---------------------------------------------------------------------------

    \74\ See section IV.J for solicitation for comment on 
mechanisms, such as alarms and automatically closing thief hatches 
that could also provide assurance that thief hatches meet this 
requirement.
    \75\ See Document ID No. EPA-HQ-OAR-2021-0317-0814.
---------------------------------------------------------------------------

    Given all of the factors described in this section (fewer 
equipment, less emissions, many are owned and operated by small 
businesses, do not contain leak-prone equipment that needs OGI to 
identify emissions), the

[[Page 74732]]

EPA is proposing quarterly AVO surveys and the closed and sealed 
requirement for thief hatches as the BSER for reducing fugitive 
emissions at small well sites. The EPA is soliciting comment on this 
definition for small well sites, including whether additional metrics 
should be used beyond equipment counts, as well as the proposed 
standards and requirements for this subcategory of sites.
    Multi-wellhead only well sites. For wellhead only well sites with 
two or more wellheads, the EPA anticipates that the same large 
emissions source (i.e., surface casing valves) would be present. In 
addition to these valves on the wellheads, these sites have additional 
piping, and thus connection points and valves that also present a 
potential source of fugitive emissions. Emissions from these types of 
components are generally smaller, and not easily identifiable using 
AVO. Further, the estimated component count for the multi-wellhead only 
well sites is at least double that of the single wellhead only well 
site (and in many cases much larger), thus, the EPA has determined that 
additional analysis including OGI monitoring is appropriate. As with 
the AVO inspection analysis for single wellhead only well sites, the 
EPA evaluated both a 0.5 percent leak generation rate and a 1.0 percent 
leak generation rate for this model plant to determine which model 
results were representative of the fugitive emissions measurement data 
provided in the same studies used for comparison for single wellhead 
only well sites analysis.
    For multi-wellhead only well sites, the baseline emissions were 
estimated at 2.66 tpy methane and 4.68 tpy methane at the 0.5 percent 
and 1.0 percent leak generation rates, respectively. Applying the 
wellhead emissions range from the U.S. DOE marginal well study to a 
site with two wellheads results in baseline methane emissions of 0.52 
to 1.12 tpy.\76\ Applying the wellhead emissions from the Rutherford, 
et al. study to a site with two wellheads and meters results in 
baseline methane emissions of 3.40 tpy. Using the average emissions 
between these 2 studies, the baseline methane emissions are 2.26 tpy, 
which is consistent with the 0.5 percent leak generation rate model 
plant results. Accordingly, the EPA is evaluating the OGI monitoring 
frequencies based on the modeled results for the 0.5 percent leak 
generation rate for purposes of this proposal. Additional details of 
the model results, including those for the 1.0 percent leak generation 
rate, are included in the Supplemental TSD for this action located at 
Docket ID No. EPA-HQ-OAR-2021-0317.
---------------------------------------------------------------------------

    \76\ The emissions for meters in the U.S. DOE marginal well 
study were negligible and do not impact the total average baseline 
emissions for this type of site.

 Table 11--Summary of Emission Reductions and Cost-Effectiveness: OGI Monitoring at Well Sites With Two or More
                                                    Wellheads
----------------------------------------------------------------------------------------------------------------
                                                 Methane      VOC      Cost-effectiveness     Incremental cost-
                                       Annual    emission   emission ----------------------     effectiveness
        Monitoring frequency          cost ($/  reduction  reduction                       ---------------------
                                      yr/site)    (tpy/      (tpy/     Methane    VOC ($/    Methane    VOC ($/
                                                  site)      site)     ($/ton)      ton)     ($/ton)      ton)
----------------------------------------------------------------------------------------------------------------
        Well Sites with Two or More Wellheads: 0.5 Percent Leak Generation Rate Single Pollutant Approach
----------------------------------------------------------------------------------------------------------------
Baseline...........................  .........       2.66       0.74  .........  .........  .........  .........
Annual.............................     $1,972       1.18       0.33     $1,677     $6.034  .........  .........
Semiannual.........................      2,327       1.79       0.50      1,300      4,675       $578     $2,078
Quarterly..........................      3,037       2.06       0.57      1,473      5,300      2,620      9,425
Bimonthly..........................      3,747       2.15       0.60      1,741      6,263      7,799     28,055
Monthly............................      5,877       2.24       0.62      2,619      9,420     23,140     83,246
----------------------------------------------------------------------------------------------------------------
         Well Sites with Two or More Wellheads: 0.5 Percent Leak Generation Rate Multipollutant Approach
----------------------------------------------------------------------------------------------------------------
Baseline...........................  .........       2.66       0.74  .........  .........  .........  .........
Annual.............................      1,972       1.18       0.33        839      3,017  .........  .........
Semiannual.........................      2,327       1.79       0.50        650      2,338        289      1,039
Quarterly..........................      3,037       2.06       0.57        737      2,650      1,310      4,713
Bimonthly..........................      3,747       2.15       0.60        870      3,131      3,899     14,028
Monthly............................      5,877       2.24       0.62      1,309      4,710     11,570     41,623
----------------------------------------------------------------------------------------------------------------

    Based on the information summarized in Table 11, under the single 
pollutant approach where all costs are assigned to methane and zero 
cost to VOC, all frequencies except monthly appear reasonable for 
methane emissions; where all costs are assigned to VOC and zero cost to 
methane, only annual, semiannual, and quarterly monitoring frequencies 
appear reasonable for VOC emissions. Under the multipollutant approach 
where the costs are divided equally between the two pollutants, all 
frequencies appear reasonable when compared directly to a baseline of 
no OGI monitoring.
    The EPA next evaluated the incremental cost associated with 
advancing to a more frequent monitoring schedule to determine if those 
additional costs are reasonable for achieving the additional emissions 
reductions. Under the single pollutant approach, the incremental cost 
of going from semiannual to quarterly monitoring for well sites with 
two or more wellheads is $2,600/ton methane and $9,400/ton of VOC. 
These incremental costs are not reasonable and are outside the range of 
costs the EPA has found reasonable for this source category. Under the 
multipollutant approach, the incremental costs of going from semiannual 
to quarterly monitoring is $1,310/ton methane and $4,713/ton VOC, which 
is within the range the EPA has found reasonable for this source 
category.
    Next the EPA evaluated whether AVO inspections should also be 
utilized, in combination with the OGI surveys to allow for faster 
identification of those larger emissions sources (i.e., surface casing 
valves) between OGI surveys. As

[[Page 74733]]

explained above, fugitive emissions from these large emission sources 
can be detected through AVO inspections, which are less expensive than 
OGI. Therefore, the EPA evaluated a combination of semiannual OGI and 
various frequencies of AVO inspections to determine if this combined 
program would be as effective as, but less expensive than, quarterly 
OGI in light of the number and significance of fugitive emissions that 
can be identified via AVO at this type of well site. The EPA analyzed 
AVO inspections at quarterly, bimonthly, and monthly frequencies only 
because annual or semiannual AVO inspection frequencies would occur at 
the same time as at least one of the OGI surveys if the EPA were to 
require OGI monitoring for multi-wellhead only well sites. Further, the 
EPA determined that some costs associated with the AVO inspections 
would be less than those provided in Table 9 because those costs are 
also included in the OGI monitoring costs in Table 8. For example, 
there would be no additional costs to read the rule, travel for 
inspections that overlap with OGI monitoring surveys, or additional 
recordkeeping system costs. That is, in the evaluation of semiannual 
OGI with quarterly AVO inspections, only two AVO inspections would be 
required outside of the OGI surveys, thus the inspection costs would be 
half what is estimated for quarterly AVO inspections. Table 12 
summarizes the results of this combined program for multi-wellhead only 
well sites.

     Table 12--Summary of Emissions Reductions and Cost-Effectiveness: Combined OGI Monitoring and AVO Inspections at Multi-Wellhead Only Well Sites
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                         Cost-effectiveness         Incremental cost-
                                                                              Methane        VOC     --------------------------       effectiveness
                     Monitoring frequency                      Annual cost    emission     emission                            -------------------------
                                                               ($/yr/site)   reduction    reduction   Methane ($/  VOC ($/ton)  Methane ($/
                                                                             (tpy/site)   (tpy/site)      ton)                      ton)     VOC ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                  Multi-Wellhead Well Sites: Includes additional travel costs Single Pollutant Approach
--------------------------------------------------------------------------------------------------------------------------------------------------------
Semiannual OGI...............................................       $2,327         1.79         0.50       $1,300       $4,653  ...........  ...........
Semiannual OGI + Quarterly AVO...............................        2,651         1.99         0.55        1,331        4,788       $1,606       $6,038
Semiannual OGI + Bimonthly AVO...............................        2,973         2.09         0.58        1,425        5,125        3,394       12,210
Semiannual OGI + Monthly AVO.................................        3,671         2.16         0.60        1,822        6,554       12,728       45,787
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                   Multi-Wellhead Well Sites: Includes additional travel costs Multipollutant Approach
--------------------------------------------------------------------------------------------------------------------------------------------------------
Semiannual OGI...............................................        2,327         1.79         0.50          650        2,327  ...........  ...........
Semiannual OGI + Quarterly AVO...............................        2,651         1.99         0.55          665        2,394          803        3,019
Semiannual OGI + Bimonthly AVO...............................        2,973         2.09         0.58          712        2,563        1,697        6,105
Semiannual OGI + Monthly AVO.................................        3,671         2.16         0.60          911        3,277        6,364       22,893
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Under the single pollutant approach, a combined program of 
semiannual OGI and quarterly or bimonthly AVO are reasonable for 
methane and VOC emissions individually. However, when incremental costs 
are considered, the costs of going from quarterly to bimonthly AVO 
inspections is not reasonable for either pollutant under the single 
pollutant approach. Under the multipollutant approach, all combinations 
appear reasonable when evaluated against a baseline of no monitoring. 
However, the multipollutant incremental costs are not reasonable for a 
combined program of semiannual OGI and bimonthly AVO because the 
multipollutant VOC costs exceed the range that the EPA considers 
reasonable for this source category at $6,105/ton VOC. Therefore, the 
EPA finds it is reasonable to consider either quarterly OGI monitoring 
or a combination of semiannual OGI and quarterly AVO as cost-effective 
measures to reduce fugitive emissions from multi-wellhead only well 
sites.
    Finally, the EPA compared the emissions reductions and costs 
associated with the quarterly OGI (most stringent and cost-effective 
OGI frequency) to the combined program of semiannual OGI with quarterly 
AVO inspections. The emissions reductions for these two monitoring 
programs are comparable (2.06 tpy of methane and 0.57 tpy of VOC for 
quarterly OGI versus 1.99 tpy of methane and 0.55 tpy of VOC for 
semiannual OGI with quarterly AVO), but the costs are not. The annual 
cost of quarterly OGI monitoring is $3,037, whereas the annual cost of 
the combined OGI and AVO program is $2,489. For a combined semiannual 
OGI and quarterly AVO program the same number of surveys would be 
conducted at the site (with 2 surveys being OGI with AVO and 2 surveys 
being AVO only). The EPA is proposing the combined program of 
semiannual OGI with quarterly AVO as the BSER for multi-wellhead only 
well sites because of the comparable emissions reductions, same number 
of total surveys per year, and lower annual costs for the program 
overall. The EPA solicits comment on this proposed standard, including 
the basis for the decision to propose semiannual OGI with quarterly AVO 
inspections rather than quarterly OGI.
    Well sites with major production and processing equipment and 
centralized production facilities. The EPA evaluated a third model 
plant, which contains major production and processing equipment. The 
EPA performed the same analyses to evaluate the BSER for fugitive 
emissions components at well sites and centralized production 
facilities with major production and processing equipment as performed 
for multi-wellhead only well sites. Table 13 summarizes the cost-
effectiveness information for each OGI monitoring frequency, and Table 
14 summarizes the costs of a combined program using both OGI and AVO.
    As discussed for the single wellhead only and multi-wellhead only 
well site analyses, the EPA modeled OGI monitoring programs for both a 
1.0 percent and 0.5 percent leak generation rate and compared the 
resulting modeled emissions to the same empirical study data to 
determine which model was more representative of the emissions at this 
type of well site. The baseline emissions resulting from FEAST for this 
model plant were 15.40 tpy methane and 8.51 tpy methane at 1.0 percent 
and 0.5 percent leak generation rate, respectively. The highest average 
site emissions were calculated at 3.3 tpy methane for large natural gas 
sites and 4.0 tpy methane for large oil sites in the U.S. DOE marginal

[[Page 74734]]

well study, which the EPA anticipates is similar to the model plant 
with major production and processing equipment. The EPA next applied 
the emissions factors from the Rutherford, et al. study to the 
equipment counts in our model plant, resulting in emissions of 7.1 tpy 
methane. These emissions suggest the 0.5 percent leak generation rate 
is more appropriate for consideration of the costs of control and 
appropriate OGI monitoring frequency for well sites and centralized 
production facilities with major production and processing equipment.

       Table 13--Summary of Emission Reductions and Cost-Effectiveness: OGI Monitoring at Well Sites With Major Production or Processing Equipment
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                         Cost-effectiveness         Incremental cost-
                                                                              Methane        VOC     --------------------------       effectiveness
                     Monitoring frequency                      Annual cost    emission     emission                            -------------------------
                                                               ($/yr/site)   reduction    reduction   Methane ($/  VOC ($/ton)  Methane ($/
                                                                             (tpy/site)   (tpy/site)      ton)                      ton)     VOC ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                      Well Sites and Centralized Production Facilities: 0.5 percent leak generation rate Single Pollutant Approach
--------------------------------------------------------------------------------------------------------------------------------------------------------
Baseline.....................................................  ...........         8.51         2.37  ...........  ...........  ...........  ...........
Annual.......................................................       $2,162         3.99         1.11         $542       $1,951  ...........  ...........
Semiannual...................................................        2,588         5.73         1.59          452        1,624         $244         $879
Quarterly....................................................        3,440         6.61         1.84          520        1,872          969        3,487
Bimonthly....................................................        4,292         6.97         1.94          616        2,217        2,398        8,625
Monthly......................................................        6,848         7.26         2.02          943        3,393        8,676       31,212
--------------------------------------------------------------------------------------------------------------------------------------------------------
                       Well Sites and Centralized Production Facilities: 0.5 percent leak generation rate Multipollutant Approach
--------------------------------------------------------------------------------------------------------------------------------------------------------
Baseline.....................................................  ...........         8.51         2.37  ...........  ...........  ...........  ...........
Annual.......................................................        2,162         3.99         1.11          271          975  ...........  ...........
Semiannual...................................................        2,588         5.73         1.59          226          812          122          439
Quarterly....................................................        3,440         6.61         1.84          260          936          485        1,744
Bimonthly....................................................        4,292         6.97         1.94          308        1,108        1,199        4,313
Monthly......................................................        6,848         7.26         2.02          472        1,697        4,338       15,606
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Based on the information summarized in Table 13 for the 0.5 percent 
leak generation rate, under the single pollutant approach where all 
costs are assigned to methane and zero cost to VOC, all frequencies 
appear reasonable for methane emissions; where all costs are assigned 
to VOC and zero cost to methane, all frequencies appear reasonable for 
VOC emissions. Similarly, under the multipollutant approach where the 
costs are divided equally between the two pollutants, all frequencies 
appear reasonable when compared directly to a baseline of no OGI 
monitoring.
    The EPA next evaluated the incremental cost associated with 
advancing to each more frequent monitoring schedule. As shown in Table 
13 for the single pollutant approach, the incremental costs of going 
from quarterly to bimonthly monitoring for these larger well sites are 
$2,398/ton methane and $8,625/ton of VOC. These incremental costs are 
outside the range of costs the EPA has found reasonable for this source 
category (i.e., $2,165/ton methane and $5,540/ton VOC). Under the 
multipollutant approach, the incremental costs of going from quarterly 
to bimonthly monitoring are $1,199/ton methane and $4,313/ton VOC, 
which is within the range the EPA has found reasonable for this source 
category.
    Next the EPA evaluated the costs of a combined program for well 
sites and centralized production facilities, using quarterly OGI as a 
baseline with AVO inspections added at bimonthly, and monthly 
frequencies to determine if this combined program would be as effective 
as, but less expensive than, bimonthly OGI. The EPA did not evaluate 
annual, semiannual, or quarterly AVO inspection frequencies because 
those would occur at the same time as at least one of the OGI surveys 
if the EPA were to require quarterly OGI monitoring for well sites and 
centralized production facilities with major production and processing 
equipment. However, the EPA is soliciting comment on the costs and 
effectiveness of a combined program of quarterly OGI surveys in 
combination with quarterly AVO inspections that are offset by one 
month, such that eight total fugitive surveys would take place over the 
course of a year. Further, the EPA determined that some costs 
associated with the AVO inspections would be less than those provided 
in Table 9 because those costs are also included in the OGI monitoring 
costs in Table 8. For example, there would be no additional costs to 
read the rule, travel for inspections that overlap with OGI monitoring 
surveys, or additional recordkeeping system costs. Table 14 summarizes 
the results of this combined program for well sites and centralized 
production facilities with major production and processing equipment.

 Table 14--Summary of Emissions Reductions and Cost-Effectiveness: Combined OGI Monitoring and AVO Inspections at Well Sites and Centralized Production
                                                                       Facilities
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                         Cost-effectiveness         Incremental cost-
                                                                              Methane        VOC     --------------------------       effectiveness
                     Monitoring frequency                      Annual cost    emission     emission                            -------------------------
                                                               ($/yr/site)   reduction    reduction   Methane ($/  VOC ($/ton)  Methane ($/
                                                                             (tpy/site)   (tpy/site)      ton)                      ton)     VOC ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                     Well Sites and Centralized Production Facilities: Assumes no additional travel costs Single Pollutant Approach
--------------------------------------------------------------------------------------------------------------------------------------------------------
Quarterly OGI................................................       $3,440         6.61         1.84         $520       $1,872  ...........  ...........

[[Page 74735]]

 
OGI + Bimonthly AVO..........................................        4,232         6.93         1.93          611        2,198        2,497        8,981
OGI + Monthly AVO............................................        5,021         7.10         1.97          707        2,545        4,616       16,608
--------------------------------------------------------------------------------------------------------------------------------------------------------
                      Well Sites and Centralized Production Facilities: Assumes no additional travel costs Multipollutant Approach
--------------------------------------------------------------------------------------------------------------------------------------------------------
Quarterly OGI................................................        3,440         6.61         1.84          260          936  ...........  ...........
OGI + Bimonthly AVO..........................................        4,232         6.93         1.93          305        1,099        1,248        4,491
OGI + Monthly AVO............................................        5,021         7.10         1.97          354        1,272        2,308        8,304
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Under the single pollutant approach, a combined program of 
quarterly OGI and bimonthly or monthly AVO are reasonable for methane 
and VOC emissions individually. When incremental costs are considered, 
the costs of going from bimonthly to monthly AVO inspections is not 
reasonable for either pollutant under the single pollutant approach. 
Under the multipollutant approach, all combinations appear reasonable 
when evaluated against a baseline of no monitoring. The multipollutant 
incremental costs are not reasonable for a combined program of 
quarterly OGI and monthly AVO. However, the EPA finds it is reasonable 
to consider either a bimonthly OGI monitoring program alone or a 
combination of quarterly OGI and bimonthly AVO as cost-effective 
measures to reduce fugitive emissions from well sites and centralized 
production facilities that include major production and processing 
equipment.
    Finally, the EPA compared the emissions reductions achieved by the 
combined quarterly OGI and bimonthly AVO program to a bimonthly OGI 
program with no AVO inspections. While both programs appear cost-
effective, the combined program achieves comparable emissions 
reductions to the bimonthly OGI program (6.93 tpy of methane and 1.93 
tpy of VOC for the combined program, compared to 6.97 tpy of methane 
and 1.94 tpy of VOC for the bimonthly OGI program) at a comparable cost 
($4,232 for the combined program compared to $4,292 for the bimonthly 
OGI program), and results in more total visits to the well site or 
centralized production facility. Specifically, a total of four OGI 
surveys and four AVO inspections would be completed, for a total of 
eight surveys at the site each year (two of the bimonthly AVO 
inspections would occur at the same time as two of the OGI surveys) 
whereas bimonthly OGI would result in six surveys of the site each 
year. Additional visits to the site create more opportunities to find 
and fix fugitive emissions, including the large emissions that can be 
detected by AVO inspections. Therefore, the EPA finds that the BSER for 
well sites and centralized production facilities with major production 
and processing equipment is quarterly OGI surveys combined with 
bimonthly AVO inspections and therefore is proposing this combined 
program as the standard for reducing fugitive emissions at these sites. 
The EPA solicits comment on this proposed standard, including the basis 
for the decision to propose quarterly OGI monitoring with bimonthly AVO 
inspections rather than bimonthly OGI monitoring.
    Because the EPA finds that the combination of quarterly OGI 
monitoring and bimonthly AVO inspections are reasonable, the EPA is 
proposing this combination of monitoring frequencies and methods as the 
BSER for well sites and centralized production facilities with major 
production and processing equipment. The EPA is specifically proposing 
to require this combination program for fugitive emissions components 
affected facilities located at well sites or centralized production 
facilities that contain the following major production and processing 
equipment:
     One or more controlled storage vessels or tank batteries,
     One or more control devices,
     One or more natural gas-driven pneumatic controllers or 
natural gas-driven pneumatic pumps, or
     Two or more pieces of major production and processing 
equipment not otherwise specified.\77\
---------------------------------------------------------------------------

    \77\ Major production and processing equipment includes 
centrifugal and reciprocating compressors, separators, glycol 
dehydrators, heater/treaters, and storage vessels.
---------------------------------------------------------------------------

    The EPA is proposing to define this subcategory as well sites with 
one or more controlled storage vessels, control devices, or natural 
gas-driven pneumatic controllers because those sources individually are 
known sources of super-emitter emissions events (see section IV.C) and 
are subject to quarterly OGI for compliance assurance (storage vessels 
and pneumatic controllers) or are subject to other continuous 
monitoring requirements (control devices). Further, the EPA is defining 
this subcategory as well sites with two or more other major production 
and processing equipment because the model plant includes two 
separators, which are another source that can contribute to large 
emissions when combined with a storage tank. As explained previously 
related to small well sites, the EPA is proposing an additional 
subcategory of well sites to recognize that this model plant may 
overstate the fugitive emissions from well sites that have only one 
piece of major production and processing equipment that is not a 
controlled storage vessel, control device, pneumatic controller, or 
pneumatic pump. Consistent with comments received on the November 2021 
proposal, the EPA understands that the industry is aware that this 
specific equipment (controlled storage vessels, control devices, and 
natural gas-driven pneumatic controllers) is more prone to emissions 
and that fugitive surveys using OGI present an opportunity to identify 
these emissions. However, the EPA is not expanding the definition of 
fugitive emissions component to include controlled tank batteries, 
control devices, or natural gas-driven pneumatic controllers as 
explained earlier in this section because those sources are subject to 
separate requirements that are intended to ensure proper operation 
(including regular inspections, in the case of controlled tank 
batteries and natural gas-driven pneumatic controllers).
    In summary, the EPA is proposing that the BSER for well sites with 
major

[[Page 74736]]

production and processing equipment and centralized production 
facilities, is a combination program consisting of bimonthly AVO 
inspections and quarterly OGI monitoring and the closed and sealed 
requirement for thief hatches (as explained in the discussion on small 
well sites).
    Well closure plans. The EPA is proposing that owners and operators 
of each well site or centralized production facility may stop the 
required fugitive emissions monitoring and repair for that site when 
the well site has been properly closed because in that event there 
should not be any equipment or other fugitive components onsite for 
monitoring. This would also help address concerns cited by many 
stakeholders regarding continuing emissions from orphaned wells and 
unplugged idled wells. In the November 2021 proposal, the EPA solicited 
comment and information on idled and unplugged wells due to the EPA's 
understanding and concern that these non-producing oil and natural gas 
wells are generally unmanned and many are in disrepair. 86 FR 63240 
(November 15, 2021). The EPA notes that ``some states and NGOs also 
have elevated concerns about the potential number of wells that could 
be abandoned in the near future as they reach the end of their 
productive lives.'' Id.
    In addition, since promulgation of NSPS OOOOa, the EPA has received 
various questions from owners and operators related to when fugitive 
emissions monitoring applies if a well is shut-in, idled, or 
permanently closed. The Agency is therefore proposing specific 
requirements in NSPS OOOOb to ensure clarity for well sites and 
centralized production facilities subject to the rule. Studies have 
shown that idled wells can have fugitive emissions, and in some cases 
these emissions can be very large.78 79 The EPA finds that 
these data demonstrate the importance of continued fugitive emissions 
monitoring on a routine basis to ensure that fugitive emissions 
continue to be addressed throughout the life of the well site, even 
during periods when the wells at the site are shut-in or idled and 
could be put back into production at a later date.
---------------------------------------------------------------------------

    \78\ Amy Townsend-Small and Jacob Hoschouer. ``Direct 
measurements from shut-in and other abandoned wells in the Permian 
Basin of Texas indicate some wells are a major source of methane 
emissions and produced water.'' 2021 Environ. Res. Lett. 16 054081. 
https://iopscience.iop.org/article/10.1088/1748-9326/abf06f.
    \79\ Eric D. Lebel, Harmony S. Lu, Lisa Vielst[auml]dte, Mary 
Kang, Peter Banner, Marc L. Fischer, and Robert B. Jackson. 
``Methane Emissions from Abandoned Oil and Gas Wells in 
California.'' Environmental Science & Technology 2020 54 (22), 
14617-14626. DOI: 10.1021/acs.est.0c05279.
---------------------------------------------------------------------------

    However, there is a point at the end of a well site's useful life 
where the EPA does anticipate the cessation of fugitive emissions 
monitoring is appropriate, when all wells at the well site have been 
permanently plugged and all equipment has been removed. To demonstrate 
that a well site has reached that point where it is appropriate to 
cease fugitive monitoring, the EPA is proposing to require owners and 
operators to develop and submit a well closure plan within 30 days of 
the cessation of production from all wells at the well site or 
centralized production facility. The plan would include: (1) The steps 
necessary to close all wells at the well site, including plugging of 
all wells; (2) the financial requirements and disclosure of financial 
assurance to complete closure; and (3) the schedule for completing all 
activities in the closure plan. The EPA is also proposing to require 
that owners and operators submit a notification to the Agency 60 days 
before beginning well closure activities. The EPA solicits comment on 
additional provisions that could be added, including, for example, 
automatic consequences for missed monitoring reports, as a means of 
assuring that companies remain engaged with the site, including 
conducting monitoring, until all the wells at the site are properly 
closed.
    Finally, the EPA is proposing that when the well closure activities 
have been completed, prior to ceasing regular monitoring, the owner or 
operator would be required to conduct a survey of the well site using 
OGI. The purpose of this survey is to ensure there are no emissions 
identified with OGI. If any emissions are identified, the owner or 
operator would be required to take steps to eliminate those emissions 
and resurvey. The EPA is proposing that once the OGI survey indicates 
no emissions are present, the well site would be considered closed and 
no further fugitive emissions monitoring would be required.
    The EPA finds that the requirements described above not only would 
allow owners and operators of well sites and centralized production 
facilities to stop fugitive emissions monitoring at a clearly defined 
point where fugitive emissions are no longer a concern at the site, 
these proposed requirements would also prevent well sites from becoming 
orphaned or left in an idled and unplugged state with no form of 
emissions monitoring and repair. The EPA assesses the continued 
monitoring of well sites will help identify emissions and maintain the 
well site such that it does not fall into disrepair. The EPA is 
soliciting comment on these planning and monitoring requirements. 
Lastly, because a well site could have a long useful life, during which 
there may be different owners or operators, the EPA is proposing to 
require owners and operators to report, through the annual report, any 
changes in ownership at individual well sites so that it is clear who 
the responsible owners and operators are until the site is plugged and 
closed and fugitive emissions monitoring is no longer required. We 
propose this reporting requirement as an important step in maintaining 
transparency for the responsible owner or operator and will also 
prevent well sites from becoming orphaned in the future. The EPA 
solicits comment on this additional reporting requirement, including 
other mechanisms for obtaining this information.
iii. Summary of Proposed Standards
    Definition of fugitive emissions component. Based on changes made 
and discussed under section IV.A.1.a.ii of this preamble, the EPA is 
proposing to define fugitive emissions component as any component that 
has the potential to emit fugitive emissions of methane or VOC at a 
well site, centralized production facility, or compressor station, 
including valves, connectors, pressure relief devices, open-ended 
lines, flanges, covers and CVS not subject to 40 CFR 60.5411b, thief 
hatches or other openings on a storage vessel not subject to 40 CFR 
60.5395b, compressors, instruments, meters, and yard piping.
    Monitoring requirements. The EPA is proposing the following 
requirements for each subcategory of well sites not located on the 
Alaska North Slope.
     Single wellhead only well sites and small well sites: 
Quarterly AVO inspections.
     Multi-wellhead only well sites: Semiannual OGI (or EPA 
Method 21) monitoring and quarterly AVO inspections at wellhead only 
well sites with two or more wellheads.
     Well sites with major production and processing equipment 
and centralized production facilities: Quarterly OGI (or EPA Method 21) 
monitoring and bimonthly AVO inspections at well sites and centralized 
production facilities with: (1) One or more controlled storage vessels 
or tank batteries; (2) one or more control devices; (3) one or more 
natural gas-driven pneumatic controllers; or (4) two or more pieces of 
major production or processing equipment not listed in items (1) 
through (3).
    Where semiannual monitoring is proposed, subsequent semiannual

[[Page 74737]]

monitoring would occur at least 4 months apart and no more than 7 
months apart. Where quarterly monitoring is proposed, subsequent 
quarterly monitoring would occur at least 60 days apart and quarterly 
monitoring may be waived when temperatures are below 0 degrees 
Fahrenheit ([deg]F) for two of three consecutive calendar months of a 
quarterly monitoring period.
    When fugitive emissions are identified through AVO inspections, the 
EPA is proposing to require that repairs be completed within 15 days 
after the first attempt. The EPA is proposing a 15-day repair timeframe 
so that the monthly AVO inspections do not overlap the repair schedule. 
When fugitive emissions are identified through OGI surveys, the EPA is 
proposing to require a first attempt at repair within 30 days of 
detecting the fugitive emissions, with final repair, including resurvey 
to verify repair, completed within 30 days after the first attempt, 
consistent with the November 2021 proposal. Finally, we are proposing 
to require owners and operators to develop a fugitive emissions 
monitoring plan that covers all the applicable requirements for the 
fugitive emissions components located at a well site or centralized 
production facility. This monitoring plan would also include specific 
procedures, defined by the owner or operator, to ensure consistency in 
surveys conducted with either OGI or EPA Method 21, and to ensure that 
these surveys are conducted appropriately for identifying fugitive 
emissions from components at the site.
    Monitoring (AVO and OGI) surveys would be required to continue 
until the owner or operator permanently closes the well site. Closure 
includes completing well closure activities specified by the owner or 
operator in a well closure plan. A final OGI survey of the well site 
would be required to ensure there are no emissions following plugging 
all of the wells at the site and completing closure activities. If 
emissions are identified during this OGI survey, the rule would require 
eliminating those emissions within the same timeline as required for 
regular OGI surveys (first attempt within 30 days of identification, 
with final repair within 30 days of the first attempt) and a resurvey 
of the whole site to verify emissions have been addressed.
    Recordkeeping and Reporting Requirements. Specific recordkeeping 
and reporting requirements would also apply for each fugitive emissions 
affected facility. Sources would be required to report the designation 
of the type of site (i.e., well site, centralized production facility, 
or compressor station) at which the fugitive emissions components 
affected facility is located. In addition, for each fugitive emissions 
components affected facility that becomes an affected facility during 
the reporting period, the date of the startup of production or the date 
of the first day of production after modification would be required for 
well sites or centralized production facility. Each fugitive emissions 
components affected facility at a well site would also be required to 
specify in the annual report what type of site it is (i.e., a single 
wellhead only well site, small well site, a multi-wellhead only well 
site, or a well site with major production and processing equipment).
    For fugitive emissions components affected facilities complying 
with the requirement to conduct surveys using AVO, the annual report 
would require the date of the survey, the total number and type of 
equipment for which leaks were identified, or, if no leaks were 
detected, a statement that there were no leaks on the day of 
inspection, the total number and type of equipment for which leaks 
identified were repaired within 15 calendar days, the total number and 
type of equipment for which no repair attempt was made within 15 days 
of the leaks being identified, and the total number and type of 
equipment placed on the delay of repair.
    For fugitive emissions components affected facilities complying 
with the requirement to monitor for fugitive emissions using OGI on a 
semiannual or quarterly basis, the following information would be 
required to be included in the annual report:
     Date of the survey,
     Monitoring instrument used,
     Any deviations from key monitoring plan elements or a 
statement that there were no deviations from these elements of the 
monitoring plan,
     Number and type of components for which fugitive emissions 
were detected,
     Number and type of fugitive emissions components that were 
not repaired,
     Number and type of fugitive emission components (including 
designation as difficult-to-monitor or unsafe-to-monitor, if 
applicable) on delay of repair and explanation for each delay of 
repair, and
     Date of planned shutdown(s) that occurred during the 
reporting period if there are any components that have been placed on 
delay of repair.
b. EG OOOOc
    In section XII.A.2 of the November 2021 proposal preamble (86 FR 
63196; November 15, 2021), the EPA proposed BSER for EG OOOOc for 
reducing methane emissions from existing well sites that was the same 
as that proposed for new well sites, with a site-wide emissions 
threshold used to determine OGI monitoring frequency. However, as 
explained for new, modified, and reconstructed well sites and 
centralized production facilities in the previous section, the EPA has 
changed approaches for evaluating the BSER for fugitive emissions 
components, which also affects the determinations for BSER for existing 
sources under EG OOOOc.
    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. Therefore, the EPA has 
evaluated the presumptive standards in EG OOOOc using the same approach 
as that for the proposed standards in NSPS OOOOb, specifically 
evaluating both the total cost-effectiveness of each monitoring option 
against a baseline of no monitoring and the incremental costs of 
increasing stringency between monitoring options. The EPA has 
determined that the methods for identifying fugitive emissions (i.e., 
AVO, OGI, and EPA Method 21), methane emissions reductions, costs, and 
cost effectiveness related to the single pollutant approach for methane 
emissions discussed above for the fugitive emissions components 
affected facility at new well sites are also applicable for the 
fugitive emissions components affected facility at existing well sites. 
Further, the fugitive emissions requirements do not require the 
installation of controls on existing equipment or the retrofit of 
equipment, which can generally be an additional factor for 
consideration when determining the BSER for existing sources. 
Therefore, the EPA is proposing that it is appropriate to use the 
analysis developed for the proposed NSPS OOOOb to also determine the 
BSER and proposed presumptive standards for the EG OOOOc. Additionally, 
the EPA is proposing the same requirement that thief hatches must be 
closed and sealed at all times, in addition to the requiring fugitive 
emissions monitoring continue until all of the wells at an existing 
well site or centralized production facility are permanently closed and 
the owner or operator has completed the same requirements for well 
closure and submitted a well closure report meeting the same 
requirements described for new sources.
    Single wellhead only and small well sites. Table 15 summarizes the 
costs associated with AVO inspections at existing single wellhead only 
well sites

[[Page 74738]]

and existing small well sites. Based on the information summarized in 
Table 15, and the explanation provided for new single wellhead only 
well sites and new small well sites, the semiannual, quarterly, and 
bimonthly inspection frequencies are all reasonable. When examining the 
incremental costs of going from quarterly to bimonthly AVO inspections, 
the costs are not reasonable at $3,618/ton methane. Therefore, the EPA 
proposes that the BSER for existing single wellhead only well sites is 
quarterly AVO inspections, and the BSER for existing small sites 
includes quarterly AVO inspections and the closed and sealed 
requirement for thief hatches (as explained in the discussion above on 
new, modified and reconstructed small well sites).

  Table 15--Summary of Methane Emissions Reductions and Cost-Effectiveness: AVO Inspections at Existing Single
                                  Wellhead Only Well Sites and Small Well Sites
----------------------------------------------------------------------------------------------------------------
                                                          Methane
                                      Annual cost ($/    emission          Total cost-        Incremental cost-
        Monitoring frequency             yr/site)     reduction (tpy/ effectiveness ($/ton  effectiveness ($/ton
                                                           site)            methane)              methane)
----------------------------------------------------------------------------------------------------------------
Annual..............................            $296            0.11                $2,579  ....................
Semiannual..........................             417            0.40                 1,048                   429
Quarterly...........................             660            0.56                 1,181                 1,511
Bimonthly...........................             904            0.63                 1,443                 3,618
Monthly.............................           1,633            0.69                 2,367                11,455
----------------------------------------------------------------------------------------------------------------

    Multi-wellhead only well sites. Table 16 summarizes the costs 
associated with OGI monitoring at multi-wellhead only well sites and 
Table 17 summarizes the costs associated with combined OGI and AVO 
surveys at multi-wellhead only well sites. Based on the information 
summarized in Table 16, the costs of annual, semiannual, quarterly, and 
bimonthly OGI monitoring is reasonable when compared to a baseline of 
no monitoring. When examining the incremental costs of going from 
semiannual OGI to quarterly OGI, the costs are not reasonable at 
$2,620/ton methane reduced. The EPA next evaluated the costs associated 
with adding AVO inspections to semiannual OGI monitoring to determine 
if additional emission reductions could be achieved at a reasonable 
cost. Based on the information summarized in Table 17, all programs 
presented are cost-effective when compared to a baseline of no 
monitoring. When examining the incremental costs of going from a 
combined program of semiannual OGI with quarterly AVO inspections to 
one with bimonthly AVO inspections, the costs are not reasonable at 
$3,394/ton methane reduced. Because the combined program of semiannual 
OGI with quarterly AVO inspections is cost-effective and would result 
in more visits to the well site, and thus provide opportunity to 
address any emissions detected, the EPA is proposing that the BSER for 
existing multi-wellhead only well sites is a combined program of 
semiannual OGI with quarterly AVO inspections.

 Table 16--Summary of Emission Reductions and Cost-Effectiveness: OGI Monitoring at Well Sites With Two or More
                                                    Wellheads
----------------------------------------------------------------------------------------------------------------
                                                          Methane
                                      Annual cost ($/    emission          Total cost-        Incremental cost-
        Monitoring frequency             yr/site)     reduction (tpy/     effectiveness         effectiveness
                                                           site)         methane ($/ton)       methane ($/ton)
----------------------------------------------------------------------------------------------------------------
Baseline............................  ..............            2.66  ....................  ....................
Annual..............................          $1,972            1.18                $1,677  ....................
Semiannual..........................           2,327            1.79                 1,300                   578
Quarterly...........................           3,037            2.06                 1,473                 2,620
Bimonthly...........................           3,747            2.15                 1,741                 7,799
Monthly.............................           5,877            2.24                 2,619                23,140
----------------------------------------------------------------------------------------------------------------

    Table 17--Summary of Methane Emissions Reductions and Cost-Effectiveness: Combined OGI Monitoring and AVO
                             Inspections at Existing Multi-Wellhead Only Well Sites
----------------------------------------------------------------------------------------------------------------
                                                          Methane
                                      Annual cost ($/    emission          Total cost-        Incremental cost-
        Monitoring frequency             yr/site)     reduction (tpy/     effectiveness         effectiveness
                                                           site)         methane ($/ton)       methane ($/ton)
----------------------------------------------------------------------------------------------------------------
Semiannual OGI......................          $2,327            1.79                $1,300  ....................
OGI + Quarterly AVO.................           2,651            1.99                 1,331                $1,606
OGI + Bimonthly AVO.................           2,973            2.09                 1,425                 3,394
OGI + Monthly AVO...................           3,671            2.16                 1,822                12,728
----------------------------------------------------------------------------------------------------------------

    Well sites with major production and processing equipment and 
centralized production facilities. Table 18 summarizes the costs 
associated with OGI monitoring and Table 19 summarizes the costs of 
combined OGI and AVO surveys at existing well sites and centralized 
production facilities with major production and processing equipment. 
The EPA is proposing the same definition for these well sites, 
including the specific equipment that

[[Page 74739]]

constitutes a well site in this subcategory (e.g., leak-prone 
equipment, such as controlled storage vessels). Based on the 
information summarized in Table 18, all monitoring frequencies appear 
cost-effective when compared to a baseline of no monitoring. When 
incremental costs are considered, the costs of going from quarterly to 
bimonthly OGI monitoring is not reasonable. The EPA then evaluated if 
AVO inspections could be added to the quarterly OGI monitoring at a 
reasonable cost. As shown in Table 19, all programs presented are cost-
effective when compared to a baseline of no monitoring. When examining 
the incremental costs of going from a quarterly OGI program to a 
combined program of quarterly OGI with bimonthly AVO inspections, the 
costs are not reasonable at $2,497/ton methane reduced. Therefore, the 
EPA is proposing quarterly OGI monitoring for these sites. In sum, the 
EPA is proposing that the BSER for existing well sites with major 
production and processing equipment and centralized production 
facilities consists of quarterly OGI monitoring and the closed and 
sealed requirement for thief hatches (as explained above in the 
discussion on new, modified or reconstructed small well sites).

    Table 18--Summary of Emission Reductions and Cost-Effectiveness: OGI Monitoring at Well Sites With Major
                                       Production or Processing Equipment
----------------------------------------------------------------------------------------------------------------
                                                          Methane
                                      Annual cost ($/    emission          Total cost-        Incremental cost-
        Monitoring frequency             yr/site)     reduction (tpy/     effectiveness         effectiveness
                                                           site)         methane ($/ton)       methane ($/ton)
----------------------------------------------------------------------------------------------------------------
Baseline............................  ..............            8.51  ....................  ....................
Annual..............................          $2,162            3.99                  $542
Semiannual..........................           2,588            5.73                   452                  $244
Quarterly...........................           3,440            6.61                   520                   969
Bimonthly...........................           4,292            6.97                   616                 2,398
Monthly.............................           6,848            7.26                   943                 8,676
----------------------------------------------------------------------------------------------------------------

    Table 19--Summary of Methane Emissions Reductions and Cost-Effectiveness: Combined OGI Monitoring and AVO
  Inspections at Existing Well Sites With Major Production and Processing Equipment and Centralized Production
                                                   Facilities
----------------------------------------------------------------------------------------------------------------
                                                          Methane
                                      Annual cost ($/    emission          Total cost-        Incremental cost-
        Monitoring frequency             yr/site)     reduction (tpy/     effectiveness         effectiveness
                                                           site)         methane ($/ton)       methane ($/ton)
----------------------------------------------------------------------------------------------------------------
Quarterly OGI.......................          $3,440            6.61                  $520  ....................
OGI + Bimonthly AVO.................           4,232            6.93                   611                $2,497
OGI + Monthly AVO...................           5,021            7.10                   707                 4,616
----------------------------------------------------------------------------------------------------------------

2. OGI Monitoring at Compressor Stations
a. NSPS OOOOb
    In the November 2021 proposal, the EPA proposed that compressor 
stations would be required to conduct quarterly OGI or EPA Method 21 
monitoring. Where OGI monitoring was used to perform the quarterly 
monitoring surveys, the EPA proposed surveys would be conducted 
according to the procedures proposed in the November 2021 proposal as 
appendix K.
    In this supplemental proposal, the EPA is retaining the proposed 
quarterly OGI (or EPA Method 21) monitoring requirement for fugitive 
emissions components affected facilities located at compressor stations 
(including the requirement that consecutive quarterly monitoring survey 
be conducted at least 60 days apart). Also, as in the November 2021 
proposal, the supplemental proposal includes the provision in the 2016 
NSPS OOOOa that the quarterly monitoring may be waived when 
temperatures are below 0 [deg]F for two of three consecutive calendar 
months of a quarterly monitoring period.
    In addition, the EPA is proposing to add a requirement to conduct 
monthly AVO monitoring at compressor stations. As discussed above for 
well sites, the EPA finds these AVO monitoring requirements can be 
conducted by any personnel at the site as indications of emissions can 
be identified without the need for specialized training. Any 
indications of fugitive emissions identified via AVO would be subject 
to repair. The EPA specifically received comments on the November 2021 
proposal that indicated that ``even though small company compressor 
stations are not manned 24 hours a day, they are visited weekly, if not 
daily.'' \80\ Therefore, no additional costs are associated with the 
proposed monthly AVO inspection requirement for compressor stations.
---------------------------------------------------------------------------

    \80\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0585 and EPA-HQ-
OAR-2021-0317-0814.
---------------------------------------------------------------------------

    While the EPA is maintaining (and strengthening in the case of the 
monthly AVO requirement) the November 2021 proposal as it relates to 
the collection of fugitive emissions components located at compressor 
stations, the EPA is not including the requirement to conduct OGI 
monitoring surveys according to the procedures that would become 
appendix K. See discussion in section IV.A.1.a.ii on comments received 
opposing this requirement. Instead, the EPA is proposing that quarterly 
surveys be performed according to the OGI procedures specified in the 
proposed regulatory text in NSPS OOOOb or according to EPA Method 21.
b. EG OOOOc
    Based on the analysis presented in section XII.A.2 of the 2021 
November proposal preamble (86 FR 63196; November 15, 2021), the 
proposed BSER for EG OOOOc for reducing methane emissions from existing 
compressor stations was quarterly monitoring (using either OGI or EPA 
Method 21).
    Based on the same public comment considerations and reasoning as 
explained above (see sections IV.A.2.a.ii

[[Page 74740]]

of this preamble) for changes to the proposed NSPS OOOOb for fugitive 
emissions at compressor stations, the EPA is proposing the same changes 
and requirements under EG OOOOc. 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 compressor 
stations. The EPA determined that the methods for identifying fugitive 
emissions (i.e., AVO, OGI, and EPA Method 21), methane emission 
reductions, costs, and cost effectiveness discussed above for the 
fugitive emissions components affected facility at new compressor 
stations are also applicable for the fugitive emissions components 
affected facility at existing compressor stations. The fugitive 
emissions requirements do not require the installation of controls on 
existing equipment or the retrofit of equipment, which can generally be 
an additional factor for consideration when determining the BSER for 
existing sources. Therefore, the EPA found it is appropriate to 
continue using the analysis developed for the proposed NSPS OOOOb to 
also determine the BSER and proposed presumptive standards for the EG 
OOOOc.
3. OGI Monitoring at Well Sites and Compressor Stations on the Alaska 
North Slope
a. NSPS OOOOb
    In the November 2021 proposal, the EPA proposed an annual 
monitoring requirement for well sites and compressor stations located 
on the Alaska North Slope, which included a requirement to follow the 
procedures outlined in the proposed appendix K where monitoring was 
conducted using OGI.
    In this supplemental proposal, the EPA is retaining the proposed 
annual monitoring requirement for well sites and compressor stations 
located on the Alaska North Slope. Consecutive annual monitoring 
surveys would be required at least 9 months apart and no more than 13 
months apart. For the reasons discussed in section IV.A.1.a.ii, the EPA 
is not including the requirement to follow the proposed procedures in 
appendix K when conducting monitoring surveys with OGI. The EPA is 
proposing that annual surveys be performed according to the OGI 
procedures specified in the proposed regulatory text in NSPS OOOOb or 
according to EPA Method 21 of appendix A-7 of this part.
b. EG OOOOc
    Based on the analysis presented in section XII.A.2 of the November 
2021 proposal preamble (86 FR 63196; November 15, 2021), the proposed 
BSER for EG OOOOc for reducing methane emissions from existing well 
sites and compressor stations located on the Alaska North Slope was 
annual monitoring.
    In this supplemental proposal, the EPA is retaining the annual 
monitoring requirement for existing well sites and compressor stations 
located on the Alaska North Slope. As discussed in the November 2021 
proposal, the same technical infeasibility issues with weather 
conditions exist for existing well sites and compressor stations 
located on the Alaska North Slope as for new well sites and compressor 
stations. Further, the EPA did not identify any other factors specific 
to existing sources located on the Alaska North Slope that would alter 
the analysis performed for new sources to make that analysis different 
for existing well sites and compressor stations. Therefore, the EPA is 
proposing a presumptive standard for reducing methane emissions from 
the fugitive emissions components designated facilities located at 
existing well sites and compressor stations located on the Alaska North 
Slope that is the same as what we are proposing for NSPS OOOOb.

B. Advanced Methane Detection Technologies

    As discussed in section XI.A.5 of the November 2021 proposal 
preamble (86 FR 63175; November 15, 2021), the EPA proposed an 
alternative screening option that would allow the use of advanced 
measurement technologies as an alternative to the use of ground based 
OGI surveys and AVO inspections to identify emissions from the 
collection of fugitive emissions components located at well sites, 
centralized production facilities, and compressor stations. In the 
November 2021 proposal, the EPA stated that we did not have enough 
information to determine how the proposed alternative standard (i.e., 
bimonthly screening using advanced measurement technologies) compared 
to the proposed BSER of OGI monitoring in that notice. Further we 
stated that information provided through comments to the November 2021 
proposal may be used to reevaluate BSER for fugitive emissions 
components at well sites and compressor stations through a supplemental 
proposal.\81\ As described below, commenters overwhelmingly supported 
the concept of an alternative screening option that would allow owners 
and operators to take advantage of advanced measurement technologies to 
detect fugitive emissions. Commenters also provided helpful information 
and input on how the alternative screening option could be made more 
useful and effective, including flexibilities that could be 
incorporated into the program design to enable the use of a wider 
variety of advanced measurement technologies. While there was 
widespread support of the concept of an alternative screening option, 
the EPA still does not have enough information to conduct the requisite 
BSER analysis \82\ for any specific advanced measurement technology to 
determine whether it would qualify as the BSER for detecting fugitive 
emissions (either in lieu of or in addition to OGI). The EPA, however, 
does anticipate that through this alternative screening option, if 
finalized as proposed and utilized by the industry, the Agency would 
gain additional information that could be used to reevaluate the BSER 
in a future rulemaking.
---------------------------------------------------------------------------

    \81\ 86 FR 63177 (November 15, 2021).
    \82\ Please see CAA section 111(a)(1) for a list of factors, 
including costs, that the EPA must take into account when 
determining whether an emission reduction system would qualify as 
the BSER.
---------------------------------------------------------------------------

    In response to this feedback, the EPA is proposing a number of 
changes to the alternative screening option that are intended to 
support the deployment and utilization of a broader spectrum of 
advanced measurement technologies and, ultimately, enable more cost-
effective reductions in emissions. These changes include a proposed 
``matrix'' which would specify several different screening frequencies 
corresponding to a range of minimum detection levels, in contrast to 
the single screening frequency and detection level permitted under the 
November 2021 proposal. In addition, we are proposing to allow owners 
and operators the option of using continuous monitoring technologies as 
an alternative to periodic screening and are proposing long- and short-
term emissions rate thresholds that would trigger corrective action as 
well as monitoring plan requirements for owners and operators that 
choose this approach.
    Lastly, we are proposing to establish a clear and streamlined 
pathway for technology developers and other entities to seek the EPA's 
approval for the use of advanced measurement technologies under this 
alternative screening option. Under this pathway, entities would seek 
approval for alternative test methods to demonstrate the performance of

[[Page 74741]]

alternative technologies, which would replace the use of OGI and AVO 
for fugitive emissions monitoring and the use of OGI for no 
identifiable emissions monitoring of covers and CVS (see section IV.K 
of this preamble) in both the proposed NSPS OOOOb and EG OOOOc. Once an 
alternative test method is approved by the EPA according to the 
proposed process, which is described in more detail below in Section 
IV.B.3, owners and operators would be able to utilize the advanced 
methane detection technology/technique in accordance with the 
alternative test method without the need for additional approval. 
Section IV.B.1 of this preamble discusses the use of advanced 
measurement technology in an alternative periodic screening approach. 
Section IV.B.2 of this preamble discusses the use of advanced 
measurement technologies in a continuous monitoring approach as a 
second alternative approach to the fugitive emissions monitoring and 
repair program and no identifiable emissions monitoring of covers and 
CVS in NSPS OOOOb and EG OOOOc. Section IV.B.3 of this preamble 
discusses the requirements for applying for an alternative test method, 
including who can submit an application for an alternative test method. 
Once an alternative test method is approved by the EPA, owners and 
operators would be able to utilize the advanced methane detection 
technology/technique in accordance with the alternative test method 
without the need for additional approval.
1. Alternative Periodic Screening
a. Summary of November 2021 Proposal
    The EPA proposed an alternative fugitive emissions monitoring and 
repair program for new, modified, or reconstructed fugitive emissions 
sources (i.e., collection of fugitive emissions components located at 
well sites, centralized production facilities, and compressor stations) 
that included bimonthly screening for large emissions events using 
advanced measurement technologies coupled with ground based OGI 
monitoring at least annually at each site. Specifically, the EPA 
proposed to allow owners and operators to comply with this alternative 
fugitive emissions standard instead of the ground-based quarterly or 
(co-proposed) semiannual OGI surveys for regulated sources, so long as 
owners and operators chose this alternative for all affected well 
sites, centralized production facilities, and compressor stations 
within a company-defined area and the methane detection technology used 
for the bimonthly screening surveys had a demonstrated minimum 
detection threshold of 10 kg/hr.
    In the November 2021 proposal, the EPA sought comment on this 
minimum detection threshold for the advanced measurement technologies 
used in the alternative screening approach and solicited data on the 
current detection sensitivity of commercially available methane 
detection technologies as deployed, as well as other data that could be 
used to support consideration of a different minimum detection 
threshold. The EPA also solicited comment on development of a survey 
matrix for the alternative screening approach option, where instead of 
prescribing one detection threshold and screening frequency, the 
frequency of screening surveys would be based on the sensitivity of the 
technology (i.e., screening surveys performed with technologies with 
the lower detection thresholds would need to be performed less 
frequently than screening surveys performed with technologies with 
higher detection thresholds).
    The November 2021 proposal also included a requirement for owners 
and operators to include information specific to the alternative 
screening approach in their fugitive emissions monitoring plan. This 
would include information on which sites are utilizing this alternative 
screening option; a description of the measurement technology used for 
screenings; verification of the methane detection threshold, with 
supporting data to support the verification; procedures for daily 
verification of sensitivity under field conditions; standard operating 
procedures; and methodology for conducting the screening. The EPA 
solicited comment on when notifications would be required for sites 
where the alternative standard is applied and whether submission of the 
monitoring plan and/or Agency approval before utilizing the alternative 
standard was necessary to ensure consistency in screening survey 
procedures in the absence of finalized methods or procedures.
    When fugitive emissions are detected through a periodic screening 
survey, the EPA proposed to require a ground based OGI survey of all 
fugitive emissions components at the site within 14 days of the 
screening survey. Due to the significance of the emissions events 
detected through screening, an expeditious timeframe was proposed, but 
the EPA requested additional information to fully evaluate the 
appropriateness of this proposed 14-day deadline for a follow-up OGI 
survey. Further, the EPA proposed to require repair of all fugitive 
emissions identified during the follow-up OGI survey in accordance with 
the same repair deadlines as those for regular fugitive surveys (i.e., 
a first attempt at repair within 30 days of the OGI survey and final 
repair completed within 30 days of the first attempt). However, because 
large emissions events, especially those identified during the 
screening surveys, contribute disproportionately to emissions, the EPA 
solicited comment on creating a tiered repair deadline requirement that 
would be based on the severity of the fugitive emissions identified. 
The EPA also noted that some equipment types with large emissions 
warrant a requirement for a root cause analysis rather than simply 
requiring the equipment to be repaired and solicited comment on how a 
root cause analysis with corrective action approach could be applied in 
the proposed alternative screening approach.
b. Changes to Proposal and Rationale
    The EPA received overwhelming support for the inclusion of an 
option to use advanced technologies for periodic screenings as an 
alternative to the fugitive emissions monitoring and repair program 
proposed in NSPS OOOOb and EG OOOOc. However, commenters remarked that 
the Agency failed to provide sufficient supporting evidence for the 
proposed minimum detection threshold of 10 kg/hr. Commenters provided 
alternative minimum detection thresholds and/or monitoring frequencies; 
many of these commenters provided supporting evidence for equivalency 
to the proposed fugitive emission monitoring and repair program in NSPS 
OOOOb and EG OOOOc, including results from LDAR program effectiveness 
models, such as FEAST. However, the results of these models varied 
widely, and as such, it was difficult to compare the different 
thresholds and frequencies presented by commenters. Additionally, one 
commenter suggested the EPA should investigate the role of modeling in 
equivalency demonstrations because the modeling outputs are highly 
impacted by the model inputs and assumptions made in the models.\83\ 
Commenters also encouraged the EPA to adopt a survey matrix for the 
alternative screening approach option that would allow owners and 
operators to vary the frequency of periodic screening surveys based on 
the detection sensitivity of the screening survey technology. 
Commenters stated that the EPA should

[[Page 74742]]

use existing publicly available LDAR program effectiveness models \84\ 
to determine a matrix of survey frequencies and detection thresholds 
that would provide a demonstration of equivalency between the 
alternative screening and the standard fugitive emissions monitoring 
and repair program.
---------------------------------------------------------------------------

    \83\ See Document ID No. EPA-HQ-OAR-2021-0317-0747.
    \84\ Currently, the free publicly available simulation models 
are Fugitive Emissions Abatement Simulation Toolkit (FEAST) and Leak 
Detection and Repair Simulator (LDAR-Sim).
---------------------------------------------------------------------------

    Based on these comments and subsequent discussions with 
commenters,\85\ the EPA decided that the best course of action for 
determining equivalency between different fugitive emission programs 
would be to run one of the leak detection and repair program 
effectiveness models with a set of standardized model inputs. For this 
effort, the EPA chose to conduct the modeling using FEAST so we could 
directly compare alternatives to the results of the OGI fugitive 
emissions program proposed as the BSER described in section IV.A of 
this preamble.\86\
---------------------------------------------------------------------------

    \85\ See February 18, 2022, memorandum, Summary of Meeting with 
American Petroleum Institute, and February 28, 2022, memorandum, 
Summary of Meeting with Environmental Defense Fund located at Docket 
ID No. EPA-HQ-OAR-2021-0317.
    \86\ The EPA used FEAST version 3.1 to model the various 
programs. While the EPA used FEAST in this modeling exercise, the 
EPA would expect other available modeling simulation tools to 
produce similar results.
---------------------------------------------------------------------------

    Based on recent aerial and satellite studies,\87\ \88\ a primary 
advantage of more frequent screening with advanced technologies is to 
quickly identify large emission events (commonly referred to as 
``super-emitters''). These super-emitters may be the result of large 
leaks from fugitive emissions components, but may also result from 
other sources, such as unlit flares or process malfunctions. Therefore, 
for this equivalency assessment, the EPA included emissions from other 
sources beyond fugitive emissions components that contribute to these 
super-emitters. This emissions distribution was developed using aerial 
study data from Cusworth, et al.,\89\ and supplemented to include 
additional leaks between the lower limits of detection of the aerial 
surveys (about 15 to 20 kg/hr) and high-flow samplers commonly used in 
ground-level quantification studies (maximum quantification limit of 
about 9 kg/hr). The EPA assumed the small model plants (Model Plants 1 
and 2) have one potential super-emitter source and that the larger 
model plant (Model Plant 4) has two potential super-emitter sources. 
The EPA evaluated the impact of different super-emitter frequencies but 
conducted the equivalency modeling using the 1.0 percent leak 
generation rate based on data from Zavala-Araiza, et al.\90\ 
Additionally, the EPA performed a sensitivity analysis where we assumed 
a 1.0 percent leak generation rate for larger emissions sources 
commonly identified using aerial screening technologies (>26 kg/hr) and 
a 0.5 percent leak generation rate for fugitive emissions components 
consistent with the analysis for OGI and AVO programs described in 
section IV.A. More detail on the FEAST modeling assumptions and 
simulations is provided in the Supplemental TSD for this action located 
at Docket ID No. EPA-HQ-OAR-2021-0317. The EPA solicits comment on the 
use of LDAR effectiveness models in the development of the requirements 
for the alternative screening approach, specifically on the 
appropriateness of the inputs and assumptions used in the EPA's FEAST 
modeling simulations.
---------------------------------------------------------------------------

    \87\ Chen, Yuanlei, et al. 23 Mar 2022, https://doi.org/10.1021/acs.est.1c06458.
    \88\ Irakulis-Loitxate, Itziar, et al. 30 June 2021, https://doi.org/10.1126/sciadv.abf4507.
    \89\ Cusworth, Daniel, et al. 2 June 2021, https://pubs.acs.org/doi/10.1021/acs.estlett.1c00173.
    \90\ Zavala-Araiza, Daniel, et al. 16 Jan 2017, https://doi.org/10.1038/ncomms14012.
---------------------------------------------------------------------------

    In this action, the EPA is revising the proposal for the 
alternative screening approach to provide additional flexibility to 
owners and operators to show that the advanced technology for which 
they are seeking approval would reduce fugitive emissions at least 
equivalent to the reduction under the proposed fugitive emission 
monitoring and repair program in NSPS OOOOb and EG OOOOc, as well as 
the proposed covers and CVS requirements in NSPS OOOOb and EG OOOOc. 
Instead of requiring a fixed screening survey frequency for all 
technologies, the EPA is proposing a survey matrix, where the minimum 
detection threshold of the screening technology determines the 
frequency of screening surveys and whether an annual OGI ground-based 
survey is needed as a supplement to the periodic screening surveys. 
Tables 20 and 21 present the details of the screening matrix for 
facilities required to conduct quarterly and semiannual OGI ground-
based monitoring under the proposed fugitive emissions monitoring and 
repair program in NSPS OOOOb and EG OOOOc, respectively. Based on the 
FEAST modeling the EPA performed, technologies with a minimum detection 
threshold above 30 kg/hr could not be deemed equivalent to the proposed 
fugitive emissions monitoring and repair program in NSPS OOOOb and EG 
OOOOc at any screening survey frequency, even when coupled with an 
annual OGI ground-based survey. As such, the alternative periodic 
screening approach is limited to technologies with a minimum detection 
threshold less than or equal to 30 kg/hr.

 Table 20--Survey Matrix for Alternative Periodic Screening Approach for
        Affected Facilities Subject to Quarterly OGI Monitoring a
------------------------------------------------------------------------
                                                            Minimum
                                                           detection
             Minimum screening frequency                  threshold of
                                                           screening
                                                         technology \b\
------------------------------------------------------------------------
Quarterly + Annual OGI...............................          <=1 kg/hr
Bimonthly............................................          <=2 kg/hr
Monthly..............................................          <=4 kg/hr
Bimonthly + Annual OGI...............................         <=10 kg/hr
Monthly + Annual OGI.................................         <=30 kg/hr
------------------------------------------------------------------------
\a\ Well sites with major production and processing equipment,
  controlled storage vessels, natural gas-driven pneumatic controllers,
  associated covers and closed vent systems, and control devices,
  centralized production facilities, and compressor stations.
\b\ Based on a probability of detection of 90 percent.

[[Page 74743]]

 Table 21--Survey Matrix for Alternative Periodic Screening Approach for
        Single and Multi-Wellhead Only Sites and Small Well Sites
------------------------------------------------------------------------
                                                            Minimum
                                                           detection
             Minimum screening frequency                  threshold of
                                                           screening
                                                         technology \a\
------------------------------------------------------------------------
Semiannual...........................................          <=1 kg/hr
Triannual............................................          <=2 kg/hr
Triannual + Annual OGI...............................          <=5 kg/hr
Quarterly + Annual OGI...............................         <=15 kg/hr
Monthly + Annual OGI.................................         <=30 kg/hr
------------------------------------------------------------------------
\a\ Based on a probability of detection of 90 percent.

    These survey matrices will provide owners and operators who choose 
to implement the alternative periodic screening approach a wider 
selection of methane detection technologies from which to choose. The 
matrices also provide clear goals for vendors interested in the 
development of future technologies for methane detection. The EPA 
solicits comments on the survey matrices developed for the alternative 
periodic screening approach. Specifically, the EPA is interested in 
comments regarding the applicability of this matrix to both currently 
available technologies and those currently in development. Further, 
where specific technologies may not easily work within the context of 
the proposed matrix, we are soliciting detailed information on how 
those specific technologies work, including empirical data that would 
allow for additional evaluation of parameters in the proposed matrix; 
how emissions reduction equivalency can be demonstrated for those 
technologies compared with the standard OGI work practice; and changes 
that would be needed to the proposed matrix and the basis for those 
changes. Finally, we are soliciting feedback from owners and operators 
on ways to improve and further incentivize use of the proposed matrix 
approach to ensure they are comfortable utilizing any approved 
alternative technologies and test methods.
    To reflect changes made to the proposed alternative periodic 
screening approach, the EPA is also modifying the proposed requirements 
for site-specific monitoring plans. The EPA is proposing to allow 
owners and operators to develop a site-specific monitoring plan or to 
develop a monitoring plan that covers multiples sites. At a minimum, 
the monitoring plan would need to contain the following information: 
(1) Identification of each site that will be monitored through periodic 
screening, including latitude and longitude coordinates; (2) 
identification of the test method(s) used for the periodic screening; 
(3) identification and contact information for the entity performing 
the periodic screening; (4) frequency for conducting periodic 
screenings; (5) procedures for conducting ground-based monitoring 
surveys in response to confirmed emission detection events from 
periodic screening surveys; (6) procedures and timing for identifying 
and repairing fugitive emissions components, covers, and CVS; (7) 
procedures and timing for verifying repairs for fugitive emissions 
components, covers, and CVS, and (8) recordkeeping and retention 
requirements.
    The EPA is also clarifying the timeframes for when owners and 
operators must conduct the initial periodic screening survey when 
complying with the alternative periodic screening standard. In the 
November 2021 proposal, the EPA did not include timeframes for 
initiating periodic monitoring. The EPA is proposing that, for the 
initial periodic screening survey must be conducted within 90 days of 
the startup of production for each fugitive emissions components 
affected facility and/or storage vessel affected facility located at a 
new, modified, or reconstructed well site or centralized production 
facility and have not begun any fugitive monitoring; within 90 days of 
startup for each fugitive emissions components affected facility and 
storage vessel affected facility located at a new compressor station; 
and within 90 days of modification for each fugitive emissions 
components affected facility and storage vessel affected facility 
located at a modified compressor station. This 90-day initial screening 
requirement is the same as that required for the OGI-based fugitive 
emissions surveys. Additionally, the EPA is proposing that the initial 
periodic screening survey must be conducted no later than the date of 
the next required OGI fugitive emissions survey for any affected 
facility that was previously complying with the proposed fugitive 
emissions monitoring and repair program and proposed covers and CVS 
requirements in NSPS OOOOb and EG OOOOc. The EPA solicits comment on 
the proposed timing to perform the initial periodic screening survey, 
including information to support different timeframes.
    When the periodic screening survey identifies emissions, the EPA is 
proposing to require a ground-based survey using OGI to identify the 
source of the emissions and any other fugitive emissions present. Any 
fugitive emissions identified during this ground-based survey would be 
subject to repair requirements. For fugitive emissions components, the 
EPA is proposing to require a completion of repairs within 30 days of 
the screening survey. The EPA is proposing that if the ground-based 
survey confirms that emissions were caused by a failure of a control 
device, the owner or operator must initiate a root cause analysis and 
determine appropriate corrective action within 24 hours of the ground-
based survey. Because a failure of a control device would likely result 
in violations of the standards, the EPA is proposing appropriate 
corrective action should be taken as soon as possible to address these 
failures. Similarly, for covers and CVS, which are either fugitive 
components or are subject to the proposed cover and CVS requirements, 
the EPA is proposing to require repair within 30 days of the screening 
survey. The EPA is also proposing that if a leak or defect in a cover 
or CVS is identified, the owner or operator would be required to 
perform a root cause analysis to determine the cause of emissions from 
the cover or CVS within five days of completing the ground-based 
inspection, in addition to requiring repair within 30 days of the 
screening survey. The root cause analysis should include a 
determination as to whether the system was operated outside of the 
engineering design analyses and

[[Page 74744]]

whether updates are necessary for the system. Because covers and CVS 
are required to be designed and operated with no identifiable 
emissions, indications of emissions from these sources could result in 
violations of the CVS requirements where the CVS is not a fugitive 
emissions component. Therefore, the EPA is proposing that appropriate 
corrective actions should be taken to resolve the emissions and ensure 
that the no detectable emissions standard is continuously met. Examples 
of corrective actions might include replacement of gaskets with a 
material more suitable for the composition of materials in the storage 
vessel or redesign of the entire CVS to ensure pressure setpoints are 
appropriate for relief devices on storage vessels. The EPA understands 
that the length of time necessary to complete corrective actions will 
vary based on the specific action taken. Therefore, we are soliciting 
comment on an appropriate deadline by which all corrective actions 
should be completed that would account for variability in complexity 
for such actions.
2. Alternative Continuous Monitoring Systems
a. Summary of November 2021 Proposal
    In the November 2021 proposal, the EPA recognized that the 
alternative screening approach as outlined above may not be well suited 
to continuous monitoring technologies, such as sensors or open-path 
technology, even though these technologies may meet the minimum methane 
detection threshold (86 FR 63176; November 15, 2021). To incentivize 
these continuous monitoring technologies, which could be valuable tools 
in quickly detecting large emissions events, as well as identifying 
when emissions at the site begin to rise, the EPA requested information 
that could be used in an equivalence demonstration and would allow for 
the development of a flexible framework that could cover multiple types 
of continuous monitoring technologies and be used as a second 
alternative approach to the fugitive emissions monitoring and repair 
program in NSPS OOOOb and EG OOOOc. Specifically, the EPA requested 
information on the number of continuous monitors needed on a site, 
placement criteria for these monitors, response factors, minimum 
detection levels, frequency of data readings, how to interpret the 
monitor data to determine the difference between detected emissions and 
baseline emissions, how to determine allowable emissions versus leaks, 
the meteorological data criteria, measurement systems data quality 
indicators, calibration requirements and frequency of calibration 
checks, how downtime should be handled, and how to handle situations 
where the source of emissions cannot be identified even when the 
monitor registers a leak.
b. Changes to Proposal and Rationale
    In response to the solicitation for comment on the development of a 
framework for continuous monitoring technologies in the November 2021 
proposal, the EPA received comments from vendors, trade groups, 
industry, and environmental groups in support of developing a framework 
for these technologies. Many of these commenters discussed the benefits 
of continuous monitoring systems including the low detection 
sensitivities of the technologies, the potential savings involved in 
identifying the largest leaks in near real time, and the potential to 
repair leaks on a much quicker timeframe. The EPA is proposing a 
framework for continuous monitoring technologies that is akin to the 
fenceline monitoring work practice promulgated by the EPA in 2015 as 
part of the National Emissions Standards for Hazardous Air Pollutants 
(NESHAP) for the petroleum refinery sector (80 FR 75178; December 1, 
2015). Under this proposed approach, an owner or operator utilizing 
continuous monitoring technologies would conduct a root cause analysis 
and corrective action whenever a methane emission rate action-level is 
exceeded at the boundary of a facility.
    The EPA is proposing methane emissions rate (i.e., kg/hr) based 
action levels instead of methane concentration (e.g., ppmv) based 
action levels (as in the Refineries NESHAP) in order to: (1) Account 
for upwind contributions from other sites and meteorological effects 
and (2) allow the Agency to evaluate the methane emissions reductions 
achieved by this framework, thus providing for a metric to demonstrate 
equivalency with the proposed fugitive emissions monitoring and repair 
program and proposed covers and CVS requirements in NSPS OOOOb and EG 
OOOOc. Through the comments received and subsequent discussions with 
commenters,\91\ the EPA has gathered information on how these 
continuous monitoring systems have been applied and how owners and 
operators use the information from these systems to initiate a response 
to identify and repair leaks. The application of these systems appears 
to vary widely across the industry, with no consistent standard 
currently employed. This is especially true for how sources initiate 
identification of the cause of a leak. To standardize the use of these 
systems across the industry, the EPA is proposing two action levels in 
this alternative continuous monitoring approach: (1) A long-term action 
level to limit emissions over time and (2) a short-term action level to 
identify large leaks and malfunctions. Both action levels would apply 
to all owners and operators choosing to use this alternative, and a 
root cause analysis and corrective action would be triggered when 
either action level is exceeded. The proposed long-term action levels 
are developed from the same FEAST Model used for the development of the 
proposed survey matrix for periodic screening and the action-levels are 
based on the annual emissions (including super-emitters) of our Model 
Plant 2 and Model Plant 3 discussed in section IV.A.2 of this preamble. 
Based on this data, the EPA is proposing an action-level of 1.2 kg/hr 
\92\ for sites consisting of only wellheads and 1.6 kg/hr \93\ for all 
other well sites and compressor stations with equipment. This long-term 
action level would be based on a rolling 90-day average, where the 90-
day average would be recalculated each day. The EPA is also proposing a 
short-term action-level of 15 kg/hr for sites consisting of only 
wellheads and 21 kg/hr for other well sites and compressor stations. 
These action levels are based on the same magnitude of emissions as the 
long-term action level; however, the rates are defined over the period 
of seven days. The short-term action level would be based on a rolling 
7-day average, where the 7-day average would be recalculated each day. 
The EPA solicits comment on the proposed short-term and long-term 
action levels. The EPA is also aware of industry led efforts \94\ to 
minimize methane emissions through the entirety of the value chain 
using the percentage of intensity or production as a metric. The EPA is 
soliciting comment on the potential use of intensity or production in 
the development of action levels, including appropriate thresholds for 
setting such action levels on both a short-term and long-term basis.
---------------------------------------------------------------------------

    \91\ See memorandum, Summary of Meetings on Alternative 
Screening and Continuous Monitoring Systems located at Docket ID No. 
EPA-HQ-OAR-2021-0317.
    \92\ 11.6 tons per year methane.
    \93\ 15.5 tons per year methane.
    \94\ One Future Coalition.
---------------------------------------------------------------------------

    The EPA is aware of other continuous monitoring systems using 
technologies that are not designed to quantify a site-level methane 
emissions rate (e.g.,

[[Page 74745]]

camera based continuous systems). While the EPA believes these systems 
could be useful in a methane mitigation program, they are not suitable 
for the proposed alternative continuous monitoring approach because 
they are not capable of quantifying site-level methane emissions, which 
is the basis for the equivalency demonstration of the proposed 
alternative continuous monitoring approach. That said, the EPA solicits 
comment on how these types of systems could fit within the alternative 
continuous monitoring approach, what action levels should be applied to 
a non-emission rate based continuous monitoring system, and data to 
support those action levels in order to conduct an equivalency 
demonstration. The EPA also solicits comment on whether a different 
type of approach should be used for these other types of continuous 
monitoring systems, and if so, what that approach would look like and 
how equivalency could be demonstrated between the approach and the 
proposed fugitive emissions monitoring and repair program and proposed 
covers and CVS requirements in NSPS OOOOb and EG OOOOc.
    The EPA is proposing that owners and operators must initiate a root 
cause analysis within 5 calendar days of an exceedance of either the 
short-term or long-term action level. Additionally, the EPA is 
proposing that the initial corrective action identified must be 
completed within five calendar days of an exceedance of the short-term 
action level and within 30 calendar days of an exceedance of the long-
term action level. If, upon completion of the initial corrective 
actions, the continuous monitor readings remain above an action level, 
or if all identified corrective action measures require more than 30 
days to complete, the owner or operator would be required to develop a 
corrective action plan and submit it to the Administrator within 60 
calendar days of the initial action level exceedance. The EPA is 
soliciting comment on the proposed requirements for the root cause 
analysis and corrective action, the timeframes for conducting these 
activities, and the requirement for corrective action plan submittals.
    In order to ensure that the continuous monitoring systems used in 
the alternative continuous monitoring approach are sensitive enough to 
trigger at the proposed action levels, the EPA is proposing that the 
continuous monitoring systems must have a detection level an order of 
magnitude less than the proposed action level and that the system must 
produce a valid mass emissions rate (i.e., kg/hr) from the site at 
least once every twelve hours. The EPA is also proposing requirements 
related to operability of the monitors within the continuous monitoring 
system. Specifically, the EPA is proposing that the operational 
downtime of the continuous monitoring system, or the time that any 
monitor fails to collect or transmit quality assured data, must be less 
than or equal to 10 percent on a 12-month rolling average, where the 
12-month average is recalculated each month. We are soliciting comment 
on this approach to addressing downtime and other ways to address 
system downtime and the consequences of that downtime.
    Similar to the alternative periodic screening approach, owners and 
operators who choose to implement the alternative continuous monitoring 
approach must develop a monitoring plan. The monitoring plan can either 
be a site-specific monitoring plan or cover multiples sites. At a 
minimum, the monitoring plan would need to contain the following 
information: (1) Identification of each site that will be monitored 
through periodic screening, including latitude and longitude 
coordinates; (2) identification of the test method(s) used for the 
continuous monitoring; (3) identification and contact information for 
the entity performing the continuous monitoring if the continuous 
monitoring system is administered through a third-party provider; (4) 
number and location of monitors; (5) system calibration procedures and 
schedules; (6) identification of critical components and procedures for 
their repairs; (7) procedures for out of control periods; (8) 
procedures for determining when a fugitive emissions event is detected 
by the continuous monitoring technology; (9) procedures and timing for 
identifying and repairing fugitive emissions components, covers, and 
CVS; (10) procedures and timing for verifying repairs for fugitive 
emissions components, covers, and CVS, and (11) recordkeeping and 
retention requirements.
    The EPA is proposing that owners and operators who choose to comply 
with the alternative continuous monitoring approach must install and 
begin conducting monitoring with the continuous monitoring system 
within 120 days of the startup of production for each fugitive 
emissions components affected facility or storage vessel affected 
facility located at a new, modified, or reconstructed well site or 
centralized production facility; within 120 days of startup for each 
fugitive emissions components affected facility and storage vessel 
affected facility located at a new compressor station; and within 120 
days of modification for each fugitive emissions components affected 
facility and storage vessel affected facility located at a modified 
compressor station. Additionally, the EPA is proposing the continuous 
monitoring system must begin monitoring no later than the date of the 
next scheduled OGI monitoring survey for any affected facility that was 
previously complying with the proposed fugitive emissions monitoring 
and repair program and proposed covers and CVS requirements in NSPS 
OOOOb and EG OOOOc. The EPA solicits comment on the proposed timing to 
install and begin conducting monitoring with the continuous monitoring 
system, including information to support different timeframes.
    The EPA is soliciting comment on this proposed alternative 
continuous monitoring approach, especially the use of site-level 
methane emissions as a surrogate for VOC emissions, the practicality of 
implementing the proposed framework, and any additional data on how 
continuous monitoring technologies have been deployed at well sites, 
centralized production facilities, and compressor stations. The EPA 
proposes to use the continuous monitoring system to confirm the 
effectiveness of the corrective action and has proposed additional 
repair and notification requirements for when corrective action is 
delayed or when the corrective action is ineffective.
3. Alternative Test Method Approval
a. Summary of November 2021 Proposal
    The EPA solicited comment on whether owners and operators choosing 
to comply with the alternative periodic screening approach would need 
to submit their monitoring plan to the delegated authority and whether 
Agency approval was necessary before the owner or operator could 
implement the alternative. The EPA proposed that EPA approval may be 
necessary to ensure consistency in screening survey procedures in the 
absence of finalized methods and procedures.
b. Changes to Proposal and Rationale
    The EPA received comments from industry, state agencies, and non-
governmental organizations acknowledging that review and approval of 
individual monitoring plans increases the burden on industry. 
Additionally, the review of these monitoring plans increases the burden 
on delegated authorities to evaluate the alternative technologies and 
may result

[[Page 74746]]

in inconsistent application or variable approvals for the same 
technology between different states. The EPA also received direct 
comment \95\ from one state that expressed that the EPA should serve as 
the clearinghouse for approving these advanced measurement techniques.
---------------------------------------------------------------------------

    \95\ See Document ID No. EPA-HQ-OAR-2021-0317-0763.
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    The EPA continues to find that, prior to implementation, approval 
of the technologies used in the alternative periodic screening approach 
and the alternative continuous monitoring approach is necessary due to 
the lack of standard methods and performance specifications for these 
types of systems. Approval of these systems will allow a wider range of 
methane detection techniques to be applied, but also allow the Agency 
to provide more specific guidance on the proper operation of these 
systems. Based on the comments received, the EPA is proposing to 
require these systems to be approved by the Administrator under the 
alternative test method provisions in 40 CFR 60.8(b)(3) instead of 
owners and operators seeking approval of these systems through site-
specific monitoring plans. The use of the alternative test method 
provisions has typically been applied to the approval of alternative 
test methods used to conduct performance testing to demonstrate 
compliance with a numerical emission standard. While work practice 
standards are not numerical emission standards, there is precedent for 
approving alternative test methods within work practice standards, so 
long as the change in the testing or monitoring method or procedure 
will provide a determination of compliance status at the same or higher 
stringency as the method or procedure specified in the applicable 
regulation.96 97 The EPA is soliciting comment on the use of 
this provision at 40 CFR 60.8(b)(3) for the approval of the alternative 
test method for an alternative technology for measurements within the 
proposed alternative periodic screening approach and the proposed 
alternative continuous monitoring approach.
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    \96\ In amendments to the approval of state programs and 
delegation of federal authorities, the EPA clarified that certain 
provisions within work practices, such as those related to 
compliance and enforcement provisions, are delegable provisions. In 
particular, the EPA stated that monitoring requirements are 
delegable. See 65 FR 55810 (September 14, 2000).
    \97\ The fenceline monitoring work practice in 40 CFR part 63 
subpart CC allows owners and operators to seek an alternative test 
method for use of technologies other than the prescribed sorbent 
tube monitoring with Method 325 A and B of appendix A to 40 CFR part 
63. See 40 CFR 63.658(k)(1).
---------------------------------------------------------------------------

    Once an alternative test method for an alternative technology has 
been approved, if it is broadly applicable, the EPA will post it to the 
Emission Measurement Center website.\98\ Any owner or operator who 
meets the specific applicability for the alternative test method, as 
outlined in the alternative test method, may use the alternative test 
method to comply with the alternative periodic screening approach or 
alternative continuous monitoring approach. The owner or operator would 
be required to notify the Administrator of adoption of the alternative 
periodic screening approach or alternative continuous monitoring 
approach in the first annual report following implementation of the 
alternative standard. The owner or operator's fugitive emissions 
monitoring plan would identify the approved alternative test method(s) 
the owner or operator is using the alternative periodic screening 
approach or alternative continuous monitoring approach.
---------------------------------------------------------------------------

    \98\ https://www.epa.gov/emc/oil-andgas-approved-alternative-test-methods.
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    In an effort to streamline the approval process and reduce the time 
needed for processing these request for alternative test methods, the 
EPA is proposing the following pre-qualifications for those requesting 
approval of their technology: (1) Requestors are limited to any 
individual or organization located in or that has representation in the 
U.S.; (2) requestor must have direct knowledge of the design, 
operation, and characteristics of the underlying technology; (3) the 
underlying technology must have been applied to methane measurements in 
the oil and gas production, processing, and/or transmission and storage 
sectors either domestically or internationally; (4) the technology must 
be a commercial product, meaning it has been sold, leased, or licensed, 
or offered for sale, lease, or license, to the general public. While 
the EPA has based these pre-qualifications on comments received from 
vendors or advanced methane detection technologies, the EPA solicits 
comments on how we have characterized the pre-qualifications in this 
proposal and whether any additional pre-qualifications may be 
appropriate.
    In an effort to streamline the approval of these requests by 
ensuring adequate information is received in the request to allow a 
full evaluation of the alternative technology, the EPA is proposing 
that any application for an alternative test method contain the 
following information at a minimum: (1) The desired applicability of 
the technology (i.e., site-specific, basin-specific or broadly 
applicable across the sector); (2) a description of the measurement 
systems; (3) supporting information verifying that the technology meets 
the desired detection threshold(s) as applied in the field; (4) a 
detailed description of the alternative testing procedure(s), including 
data quality objectives to ensure the detection threshold(s) are 
maintained and procedures for a daily verification check of the 
measurement sensitivity under field conditions, and; (5) standard 
operating procedures consistent with the EPA's guidance and including 
safety considerations, measurement limitations, personnel 
qualification/responsibilities, equipment and supplies, data and record 
management, and quality assurance/quality control. The EPA solicits 
comment on the proposed information required to be submitted with the 
application of an alternative test method and whether the EPA should 
consider requiring any additional information.
    The EPA is proposing a defined timeframe for review and 
determination of alternative test method requests by the Agency. The 
EPA is proposing to issue either an approval or disapproval in writing 
to the requestor within 270 days of receipt of the request, with a 
number of milestones for acknowledgement of receipt and initial 
reviews. The EPA is also proposing a mechanism to allow a conditional 
approval of a submitted alternative test method in the event a 
determination is not made by the Agency within 270 days. Finally, the 
EPA is maintaining the authority to rescind any previous approval if we 
find it reasonable to dispute the results of any alternative test 
method used to demonstrate compliance with either the alternative 
periodic screening approach or the alternative continuous monitoring 
approach. The EPA proposes to make these approvals and the supporting 
information available to the public on an EPA supported website. The 
EPA solicits comments on the proposed timeframe to review and approve 
alternative test methods and whether alternative timelines should be 
considered.

C. Super-Emitter Response Program

    Although results vary by basin, many studies have found that the 
top five percent of sources contribute over 50 percent of the total 
emissions.\99\ There is

[[Page 74747]]

wide agreement in the peer-reviewed research that a subset of sources 
comprising the very largest emission events, commonly referred to as 
super-emitters, is typically caused by abnormal operating conditions or 
malfunctions.\100\
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    \99\ Yuanlei Chen et al., ``Quantifying Regional Methane 
Emissions in the New Mexico Permian Basin with a Comprehensive 
Aerial Survey,'' Environmental Science and Technology, Vol. 56, No. 
7 (March 2022), https://doi.org/10.1021/acs.est.1c06458.
    \100\ Daniel Zavala-Araiza et al., ``Super-emitters in Natural 
Gas Infrastructure are Caused by Abnormal Process Conditions,'' 
Nature Communications Vol. 8 (January 2017), https://doi.org/10.1038/ncomms14012; Ram[oacute]n A. Alvarez et al., ``Assessment of 
Methane Emissions from the U.S. Oil and Gas Supply Chain,'' Science, 
Vol. 361 (July 2018), https://doi.org/10.1126/science.aar7204; 
Daniel H. Cusworth et al., ``Intermittency of Large Methane Emitters 
in the Permian Basin,'' Environmental Science and Technology Letters 
Vol. 8, No. 7 (June 2021), https://doi.org/10.1021/acs.estlett.1c00173; Jeffrey S. Rutherford et al., ``Closing the 
Methane Gap in US Oil and Natural Gas Production Emissions 
Inventories,'' Nature Communications Vol. 12 (August 2021), https://doi.org/10.1038/s41467-021-25017-4; Yuanlei Chen et al., 
``Quantifying Regional Methane Emissions in the New Mexico Permian 
Basin with a Comprehensive Aerial Survey,'' Environmental Science 
and Technology, Vol. 56, No. 7 (March 2022), https://doi.org/10.1021/acs.est.1c06458.
---------------------------------------------------------------------------

    Many of the requirements of this rule, when implemented correctly, 
would result in reducing the number of super-emitter emissions events. 
For the reasons described below, the EPA is further proposing a super-
emitter response program as a backstop to address the large 
contribution of super-emitters to the pollution from this sector. For 
purposes of this program, the EPA is proposing to define a super-
emitter emissions event as quantified emissions of 100 kg/hr or greater 
of methane, a very high threshold that encompasses the largest 
emissions events.
    Recognizing that super-emitter emissions events are a significant 
source of methane and VOC emissions, the November 2021 proposal and 
this supplemental proposal contain standards and requirements that, if 
implemented correctly, would prevent (e.g., via zero-emissions 
standards for pneumatic controllers and design and operation 
requirements for flares) or detect and mitigate (e.g., via regular 
monitoring for fugitive emissions using OGI or advanced detection 
technologies) most of these large emissions events.\101\ We note that 
the estimated emission reductions in both the November 2021 proposal 
and this supplemental proposal likely undercount the emission 
reductions that would be achieved by this rule because they might not 
fully account for the emissions resulting from all super-emitter 
emissions events that would be prevented or quickly corrected as a 
result of this rule. Though we are not currently able to quantify the 
emissions reductions likely to result from preventing or more quickly 
mitigating super-emitter emissions events, we note that the information 
presented in appendix D to the RIA for this supplemental proposal 
includes model simulations suggesting that covering large emitters 
could ``significantly impact[] the expected emissions from the fugitive 
emission program.'' \102\
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    \101\ Super-emitter emissions events could also be from 
intentional venting as part of normal operations or maintenance. The 
proposed super-emitter response program discussed in this section is 
not intended to address these events.
    \102\ As stated, some of the model simulations in appendix D to 
the RIA for this supplemental proposal suggest that large-emitters 
could significantly impact the estimated emissions reductions; 
however, those simulations are not directly related to the 
definition of ``super-emitter'' included in this proposal, thus the 
emissions and emission reductions cannot be used to directly assess 
the emissions or emission reductions related to the proposed super-
emitter program. The model simulations relied on information of 
large emissions from a single basin (Permian), and available data 
suggest that the frequency of these events may vary significantly 
across different production basins, which could lead to significant 
uncertainty if the emission reductions were applied nationwide.
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    It is clear from the estimates from the two proposals that these 
methods are expected to result in the prevention, detection, and repair 
of many current super-emitters. Sites that take advantage of 
opportunities for continuous emissions monitoring offered by the 
alternative monitoring strategies the EPA has proposed may be 
particularly able to quickly identify and timely address these events.
    However, super-emitters' significant impact on the communities 
where they are located, as well as their greatly disproportionate 
contribution to emissions in total, call for additional measures to 
backstop compliance and address the unique characteristics of these 
events. The abnormal process conditions that characterize these events 
can be persistent or episodic, meaning that while some sources are 
consistent super-emitters, many such large emissions events are 
intermittent and can occur at different sites over time.\103\ A cost-
effective inspection program can therefore miss some of these super-
emitter events, even if implemented in accordance with the proposed 
standards. We further note that oil and gas facilities, in particular 
those in remote areas, may not have personnel present when super-
emitter emissions events occur. Given the large number and broad 
geographic distribution of affected sources and designated facilities 
to be regulated under this rule, the EPA also recognizes that the need 
for rigorous compliance assurance will be particularly important in 
this source category.
---------------------------------------------------------------------------

    \103\ Daniel Zavala-Araiza et al., ``Super-emitters in Natural 
Gas Infrastructure are Caused by Abnormal Process Conditions,'' 
Nature Communications Vol. 8 (January 2017), https://doi.org/10.1038/ncomms14012; Daniel H. Cusworth et al., ``Intermittency of 
Large Methane Emitters in the Permian Basin,'' Environmental Science 
and Technology Letters Vol. 8, No. 7 (June 2021), https://doi.org/10.1021/acs.estlett.1c00173.
---------------------------------------------------------------------------

    The same sophisticated research and constantly advancing new 
monitoring technologies that have contributed to our understanding of 
the serious problem of super-emitters can bolster the other standards 
and requirements included in this proposal and serve to help identify 
and mitigate any super-emitter emissions events. The super-emitter 
response program, which the EPA outlined conceptually in the November 
2021 proposal for public comment and which we are now proposing here, 
would allow the use of reliable and demonstrated remote sensing 
technology deployed by experienced, certified entities or regulatory 
authorities to find these large emissions sources. As described in the 
November 2021 proposal, this proposed super-emitter response program 
builds on the growing use of these advanced technologies by a variety 
of entities to identify and mitigate super-emitting events.
    This proposed program establishes a pathway by which an EPA-
approved entity or regulatory authority may provide credible, well-
documented identification of a super-emitter emissions event using one 
of several permitted technologies and approaches, and then notify the 
responsible owner or operator. Once notified of the event, owners and 
operators would be required to perform a root-cause analysis and take 
corrective actions to address the emissions source at their individual 
well sites, centralized production facilities, and compressor stations. 
Upon conducting the root-cause analysis, the owner or operator may 
determine that all necessary and appropriate actions have been taken 
and that no additional action is needed. However, if the owner or 
operator confirms the existence of a super-emitter emissions event that 
requires mitigation--either due to a failure to comply with one of the 
standards in this rule or due to an upset or malfunction at a source 
covered by this rule--then the owner or operator must take prompt steps 
to eliminate the super-emitter emissions event and report both its 
root-cause analysis and corrective actions to the EPA and the 
appropriate state or tribal authority. To ensure this program operates 
in a transparent manner, the EPA will make available in a document 
repository the notices to operators that the EPA receives, as well as 
the reports

[[Page 74748]]

sent to the EPA by owners and operators in response, so that notifiers, 
communities, and owners and operators have quick access to the 
information submitted to the EPA under the super-emitter provisions.
    The EPA believes that the super-emitter response program proposed 
here will provide a cost-effective and efficient mechanism for 
comprehensively detecting and addressing super-emitter emission events, 
complementing and reinforcing the other requirements of this proposal 
and securing reductions in methane as well as emissions of VOCs and 
other health-harming air pollutants. In response to the November 2021 
proposal, the EPA received comments from representatives of communities 
affected by air pollution from the oil and natural gas sector, 
including communities with environmental justice (EJ) concerns, voicing 
concern about the impacts of these emissions and support for enhanced 
monitoring efforts. The EPA anticipates that the proposed super-emitter 
response program will have important benefits for such communities and 
will create opportunities for communities to partner with entities 
engaged in remote sensing to monitor nearby sources of emissions. The 
EPA also anticipates that the proposed transparency requirements for 
notifications and for follow-up actions by owners and operators will 
provide valuable information for communities about neighboring sources 
of emissions and steps taken to mitigate them.
    This section begins with a description of the November 2021 
proposal and the comments received on that proposal, followed by a 
description of the specific criteria the EPA is proposing for 
notifications to sources of super-emitter events and subsequent 
corrective actions taken to eliminate the emissions. The EPA seeks 
comment on all aspects of this proposed program.
1. November 2021 Proposal
    As described in the November 2021 proposal, ``industry, 
researchers, and NGOs have utilized advanced methane detection systems 
to quickly identify large emission sources and target ground based OGI 
surveys. state and local governments, industry, researchers, and NGOs 
have been utilizing advanced technologies to better understand the 
detection of, sources of, and factors that lead to large emission 
events.'' See 86 FR 63177 (November 15, 2021). In that proposal, the 
EPA solicited comment on a potential program for large emission events 
that would take advantage of data from the use of advanced technologies 
that could identify super-emitter emissions events; under the program, 
if emissions were detected above a defined threshold ``by a community, 
a Federal or state agency, or any other third party, the owner or 
operator would be required to investigate the event, do a root cause 
analysis, and take appropriate action to mitigate the emissions, and 
maintain records and report on such events.'' See 86 FR 63177 (November 
15, 2021).
2. Rationale for and Summary of Proposed Program
    The EPA received numerous comments from industry, non-industry 
groups, states, tribes, and local communities articulating a range of 
views on the concept described in the November 2021 proposal. These 
comments provided valuable information and input on, among other 
issues, the potential benefits of the program and the importance of 
comprehensively addressing large emission events; implementation 
challenges and concerns that would arise in establishing a system by 
which researchers or other third parties could identify these events 
and notify owners and operators, including concerns related to ensuring 
the accuracy of such notifications and providing for safe and lawful 
monitoring of sources; and the EPA's legal authority to promulgate such 
a program under CAA section 111.
    The EPA has carefully considered these comments, in conjunction 
with various peer-reviewed studies, in designing this proposal for a 
super-emitter response program. As described below, the principal 
objective of this proposed program is to provide a comprehensive and 
effective remedy for large emission events that disproportionately 
contribute to methane emissions from the Crude Oil and Natural Gas 
source category and can be accompanied by health-harming pollution that 
affects nearby communities. However, as comments provided by a wide 
range of stakeholders emphasized, it is also imperative that any such 
program ensure the safety of entities engaged in monitoring as well as 
of owners and operators and their employees; utilize accurate, 
reliable, and rigorous methods for identifying large emission events; 
and be streamlined and efficient to administer, both for owners and 
operators of regulated sources as well as for the EPA and the states. 
The proposed program contains key features and safeguards that were 
designed with these principles in mind.
    As noted above, the EPA assesses this *COM007*program is important 
both because of the significant harm associated with super-emitter 
emissions events and the well-documented challenges in identifying 
these events. The most widely known sources of unintentional releases 
resulting in super-emitter emissions events are from controlled tank 
batteries, flares, natural gas-driven pneumatic controllers, and 
fugitive emissions components. The standards and requirements included 
in the November 2021 proposed rule and this supplemental proposal are 
expected to identify and eliminate many super-emitters when implemented 
as required. However, a cost-effective inspection program requiring 
periodic fugitive emissions surveys cannot immediately detect every 
instance of a super-emitter emissions event or quickly identify when 
equipment malfunctions occur and therefore may not capture some 
intermittent or episodic super-emitter emissions events. Further, it is 
not cost-effective to impose additional inspection costs on every 
source in hopes of detecting the small percentage of sources that 
become super-emitters. The proposed super-emitter response program 
would provide a cost-effective backstop to the rest of the regulatory 
program by directing operator attention to problems urgently requiring 
a remedy and providing useful feedback about the effectiveness of the 
other regulatory requirements.
    The EPA faced a similar situation when establishing standards for 
petroleum refineries, where cost-effective controls and inspections of 
equipment and operations would not have addressed potentially 
significant levels of emissions that could occur between regular 
inspections.\104\ In that instance, the EPA required additional 
monitoring and corrective action to address such high emissions; 
specifically, the EPA required fenceline monitoring to ``identify a 
significant increase in emissions in a timely manner (e.g., a large 
equipment leak or a significant tear in a storage vessel seal), which 
would allow corrective action measures to occur more rapidly than it 
would if a source relied solely on the traditional infrequent 
monitoring and inspection methods.'' 79 FR at 36920.\105\ The EPA is 
taking a similar approach in this supplemental proposal to address 
super-emitter emissions events in a timely manner. This program

[[Page 74749]]

is likewise motivated by the same types of considerations that led the 
EPA to establish a hotline for reporting oil spills and other 
environmental releases (e.g., https://www.epa.gov/emergency-response/national-response-center). However, unlike most oil spills, large 
releases of methane are not visible to the human eye; identifying them 
requires people with specialized equipment and expertise.
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    \104\ Proposed Rule: Petroleum Refinery Sector Risk and 
Technology Review and New Source Performance Standards, 79 FR 36880, 
36920 (June 30, 2014).
    \105\ This fenceline monitoring requirement is codified at 40 
CFR 63.658 of the National Emission Standards for Hazardous Air 
Pollutants from Petroleum Refineries, 40 CFR part 63, subpart CC.
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    The following sections first describe the details of the proposed 
super-emitter response program, including the definition of a super-
emitter emissions event under the program, the requirements for any 
party that seeks to report a super-emitter emissions event under the 
program; and the requirements for owners and operators responding to 
such report. It then describes the statutory structure for the program 
under CAA section 111.
a. Super-Emitter Response Program Design
    Threshold for a super-emitter emissions event. To clearly define 
what emissions events would be subject to the requirements of this 
program, the EPA is proposing to define a super-emitter emissions event 
as any emissions detected using remote detection methods with a 
quantified emission rate of 100 kg/hr of methane or greater. While the 
term ``super-emitter'' has been widely used to describe large emissions 
events in literature and various other discussions, no specific mass-
based or production-based rates have been formally or consistently 
applied to the term. The EPA is proposing to apply a definition, for 
purposes of this response program, that focuses on very large emissions 
events at an individual well site, centralized production facility, 
compressor station, or natural gas processing plant which warrant 
immediate investigation.
    This threshold definition of 100 kg/hr of methane takes into 
account several factors. First, this proposed super-emitter response 
program is intended to provide a mechanism to utilize high quality 
remote sensing detection of only the largest, most harmful emissions 
events, and not address all the standards and requirements of NSPS 
OOOOb and EG OOOOc that are applicable to individual affected 
facilities and associated controls. The goal of this program is to 
ensure that if, notwithstanding the other requirements in this 
proposal, a very large emissions event occurs and is detected by a 
regulatory authority or qualified third parties using particular 
technologies, that super-emitting event is quickly addressed. 
Therefore, the threshold definition of a super-emitter emissions event 
needs to be sufficiently high that it does not duplicate other actions 
(e.g., leak detection and repair) facilities are undertaking to comply 
with the applicable standards in the rule. Second, where compliance is 
achieved with the applicable standards, the EPA does not expect 
unintentional releases at these very high levels to occur in normal 
operations. Thus, the occurrence of an unintentional release at this 
emissions rate should be unusual and would clearly warrant immediate 
investigation and mitigation. Defining a super-emitter event to 
encompass these unusually large events is therefore consistent with the 
EPA's objective of establishing a backstop to the other requirements 
proposed in this rule. Third, by setting such a high threshold to 
capture the largest and most concerning emissions events, the program 
would be more feasible to implement and would properly focus resources 
on the most significant and potentially harmful sources of emissions. 
Such high rates of emissions also mean that it is cost effective to 
quickly address these super-emitters, which release more methane in a 
single week than the total methane cost-effectively prevented over the 
course of an entire year at sources covered by the fugitive emissions 
program. Fourth, as discussed immediately below, this threshold allows 
the use of remote sensing technologies that are already in use by the 
EPA, states, and third parties, which could allow the program to be 
readily implemented upon finalizing NSPS OOOOb and the subsequent state 
plans required by EG OOOOc.
    Technologies that may be used to detect a super-emitter emissions 
event. Various technologies are available for remote methane detection 
that would provide a quantified mass emissions rate, including several 
that would meet the performance criteria proposed for the alternative 
periodic screening or continuous monitoring for fugitive emissions as 
described in sections IV.B.1 and IV.B.2 of this preamble. Some 
commenters stated that thresholds should be defined that could allow 
the use of a range of technologies, without limiting to one specific 
class of technologies.\106\ Among these, as discussed in the November 
2021 proposal, the EPA described its understanding that ``some 
satellite systems are generally capable of identifying emissions above 
100 kg/hr with a spatial resolution which could allow identification of 
emission events from an individual site.'' See 86 FR 63177 (November 
15, 2021). Several commenters agreed that the use of satellites for 
detecting super-emitters was appropriate, while noting that this 
technology is continuing to advance.\107\ Further, several commenters 
raised concerns regarding potential safety or trespassing on sites with 
a program using more ground based or close-range detection 
methods.\108\
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    \106\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0605, EPA-HQ-
OAR-2021-0317-0769, EPA-HQ-OAR-2021-0317-0811, and EPA-HQ-OAR-2021-
0317-0844.
    \107\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0738, EPA-HQ-
OAR-2021-0317-0753, EPA-HQ-OAR-2021-0317-0769, and EPA-HQ-OAR-2021-
0317-1391.
    \108\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0727, EPA-HQ-
OAR-2021-0317-0730, EPA-HQ-OAR-2021-0317-0749, EPA-HQ-OAR-2021-0317-
0750, EPA-HQ-OAR-2021-0317-0763, EPA-HQ-OAR-2021-0317-0797, EPA-HQ-
OAR-2021-0317-0810, EPA-HQ-OAR-2021-0317-0814, EPA-HQ-OAR-2021-0317-
0817, EPA-HQ-OAR-2021-0317-0924, and EPA-HQ-OAR-2021-0317-0955.
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    The EPA agrees with the commenters that some flexibility is 
appropriate in the type of technology that could be utilized for the 
detection of super-emitters, provided that the technology can be safely 
deployed and will reliably identify super-emitter emissions events as 
defined in this proposal. Considering concerns for the safety of 
individuals engaged in third-party monitoring and of facility operator 
personnel, the purposes of this program as described above, and 
feedback from commenters on the performance and characteristics of 
various monitoring technologies, the EPA assesses that allowing only 
remote-sensing technologies is appropriate. Therefore, we are proposing 
to allow the use of remote-sensing aircraft, mobile monitoring 
platforms, or satellites to identify super-emitter emissions events. 
The EPA is soliciting comment on this list of technology types that 
could be applied for the identification of super-emitter emissions 
events and the threshold of 100 kg/hr of methane.
    Qualifications and requirements for notification of super-emitter 
emissions events. Next, the EPA is proposing specific requirements 
related to the notification of a super-emitter emissions event by 
regulatory authorities and qualified third-party notifiers. Several 
commenters emphasized the importance of assuring the quality and 
reliability of the data and suggested that the EPA should have a role 
in verifying the information to provide that assurance.\109\ In order 
to address concerns about the expertise of the third party identifying 
the super-emitter event, the EPA is proposing that any

[[Page 74750]]

third party interested in identifying and notifying owners and 
operators of super-emitter emissions events must be pre-approved by the 
Agency for the notification to be valid. This approval process would 
follow submission of a request for approval as a qualified third-party 
notifier to the EPA that demonstrates the potential notifier's 
technical expertise in the specific technologies and detection 
methodologies proposed for the identification of super-emitter 
emissions events (i.e., remote-sensing aircraft, mobile monitoring 
platforms, or satellite). This demonstration would include technical 
expertise in the use of the detection technology and interpretation, or 
analysis, of the data collected by the technology. The EPA would 
maintain a public list of approved qualified third-party notifiers so 
owners and operators can verify approval before being required to act 
on a notification. These approved notifiers could be any third party, 
including but not limited to technology vendors, industry, researchers, 
non-profit organizations, or other parties demonstrating technical 
expertise as described. The EPA is soliciting comment on this approval 
criteria, including whether additional criteria would be appropriate.
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    \109\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0738, EPA-HQ-
OAR-2021-0317-0938, and EPA-HQ-OAR-2021-0317-0844.
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    Once approved, a qualified notifier would be required to submit 
specific information in the notification. Providing actionable data of 
known quality to the owner or operator is essential to ensure resources 
are focused on swiftly eliminating the super-emitter emissions event. 
Therefore, the EPA is proposing that each notification must contain 
specific information to help owners and operators verify that the 
emissions are correctly linked to their site and aid in a focused 
investigation to swiftly identify the source of emissions. Specific 
information that would be required in each notification includes: (1) 
The location of emissions in latitude and longitude coordinates, (2) 
description of the detection technology and sampling protocols used to 
identify the emissions, (3) documentation depicting the emissions and 
the site (e.g., aerial imaging with emissions plume depicted), (4) 
quantified emissions rate, (5) date(s) and time(s) of detection and 
confirmation after data analysis that a super-emitter emissions event 
was present, and (6) a signed certification that the notifier is an 
EPA-approved entity for providing the notification, and the information 
was collected and interpreted as described in the notification. The EPA 
believes this level of specificity is necessary to provide owners and 
operators with credible information, and address the concerns raised by 
commenters that owners and operators could experience undue burden 
investigating emissions from monitoring data that are not collected in 
a rigorous manner. We are soliciting comment on the specific required 
elements of the notification, including whether additional requirements 
should be added to aid in verifying the credibility of this 
information.
    The EPA further proposes that the entity making the report shall 
provide a complete copy to the EPA and to any delegated state authority 
(including states implementing a state plan) at an address those 
agencies shall specify. The EPA would then promptly make such reports 
available to the public online. Third parties may also make such 
reports available to the public on other public websites. The EPA would 
generally not verify or authenticate the information in third party 
reports prior to posting.
    The EPA is seeking comment on whether it should establish a 
procedure for owners and operators to suggest that EPA reconsider the 
approval granted to a third-party notifier. One type of procedure the 
EPA has considered would be based on information provided by the owner 
or operator that demonstrates they had received more than three notices 
at the same site and from the same third party for super-emitter 
emissions events which the owner or operator demonstrates, after 
opportunity for response by the third party, that the notifications 
contain meaningful, demonstrable errors, including, for example, that 
the third party did not use the appropriate methane detection 
technology, or that the emissions event did not exceed the threshold. 
Where such demonstrable error is identified, the owner and operator 
would not be obligated to conduct the root-cause analysis and 
corrective action discussed later in this section and could, instead, 
submit a report indicating the error. The EPA would not allow use of 
this type of mechanism to dispute the accuracy of technologies that 
have been approved by the EPA. Given the intermittency of super-emitter 
emissions events, the failure of the operator to find the source of the 
super-emitter emissions event upon subsequent inspection would not be 
proof, by itself, of demonstrable error on the part of the third-party 
notifier. The EPA, in its discretion, may remove that third party from 
the pre-approved list of third-party notifiers upon demonstration by 
the owner or operator and/or a finding by the EPA that more than three 
notifications to that same owner or operator were made in error.
    The design of the super-emitter response program ensures that the 
EPA will make all of the critical policy decisions and fully oversee 
the program. The proposed framework for the super-emitter response 
program further includes a robust series of safeguards to ensure that 
these notifications represent validly collected data and evidence of a 
super-emitter emissions event. First, the qualified third party 
permitted to submit notifications must be certified by the EPA as 
having appropriate experience and expertise. Second, the qualified 
third party may only use certain remote detection technology approved 
by the EPA for use in the super-emitter response program. Third, the 
EPA would establish the threshold defining what emissions events 
detected by the qualified third parties would trigger any obligation on 
the part of the owner and operator under the program. Fourth, the EPA 
has prescribed the specific factual information that must be included 
in any appropriate notification provided to an owner or operator. And 
fifth, the EPA has proposed a mechanism for owners and operators to 
seek a revocation of a notifier's certification from the EPA should 
they establish that more than one notification contained demonstrable 
errors. Accordingly, under this framework the qualified third party 
would essentially only be permitted to engage in certain fact-finding 
activities and issue fact-based notifications within the limited 
confines that the EPA has authorized. Such fact-based notifications 
originating from third parties would not represent the initiation of an 
enforcement action by the EPA or a delegated authority.
    In addition, and as discussed in more detail later in this section, 
owners and operators would have the opportunity to rebut any 
information in a notification provided by the qualified third parties 
in their written report to the EPA, by explaining, where appropriate, 
that (a) there was a demonstrable error in the third party 
notification; (b) the emissions event did not occur at a regulated 
facility; or (c) the emissions event was not the result of malfunctions 
or abnormal operation that could be mitigated. And, as just discussed, 
the EPA proposes to retain the authority to revoke a third-party 
certification upon evidence that the notifier has made repeated, 
demonstrable errors in notifications provided to owners and operators.
    Thus, the EPA believes that the proposed program appropriately 
limits third party notifiers' discretion and retains oversight by the 
EPA over all key

[[Page 74751]]

decision-making elements of the program. In light of these 
considerations, the EPA also believes that a greater role for the 
Agency in reviewing third-party notifications would be an unnecessary 
task and duplicative of the predicate approval processes and subsequent 
revocation procedure. Indeed, were the EPA to review third-party 
notifications, such review could potentially be limited to ensuring 
that the third party is properly EPA-certified, has used an EPA-
approved remote monitoring technology, and has found emissions above 
the super emitter threshold--all of which are elements that the 
proposed program structure adequately ensures. The EPA believes other 
facts necessary to rebut the information in a notification regarding a 
particular emissions event are likely to only be known by the owner and 
operator and are best presented in their written report to the EPA. 
Moreover, given the urgency with which the EPA believes such large 
emissions events should be addressed, any additional role for the EPA 
in the notification process would unnecessarily delay mitigation of 
ongoing harms. The EPA solicits comments on these conclusions, and 
whether there would be a meaningful benefit to a greater role for the 
EPA in reviewing and/or approving third-party notifications before the 
obligation of the owner or operator to respond is triggered. And if so, 
the EPA further solicits comment on what kind of role would be 
appropriate without meaningfully delaying the mitigation of the large 
emissions events this program is intended to target.
    Addressing a super-emitter emissions event. In the November 2021 
proposal, the EPA solicited comment on what specific actions an owner 
or operator would be required to take when they are notified of the 
detection of a super-emitter emissions event. Examples of those 
specific actions were provided for comment, including verifying the 
location of the emissions, conducting ground investigations to identify 
the specific emissions source, conducting a root cause analysis, 
performing corrective action within a specific timeframe to mitigate 
emissions, and preventing ongoing and future chronic or intermittent 
events from that source. See 86 FR 63177 (November 15, 2021). One 
commenter stated that not all sources of super-emitter emissions events 
would require a root cause analysis with corrective actions because the 
emissions may not be the result of malfunctions or abnormal operation 
(e.g., an emergency blowdown of equipment).\110\ Other commenters 
stated that a root cause analysis and immediate corrective actions 
should be required for any event identified through this program.\111\
---------------------------------------------------------------------------

    \110\ See Document ID No. EPA-HQ-OAR-2021-0317-1391.
    \111\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0586, EPA-HQ-
OAR-2021-0317-0605, and EPA-HQ-OAR-2021-0317-0832.
---------------------------------------------------------------------------

    The EPA agrees with commenters that swift action must be taken when 
an owner or operator is notified about the detection of a super-emitter 
emissions event to correct any malfunction or abnormal operation that 
is identified as the cause of the event. First, the owner or operator 
should confirm that the reported emissions event is traceable to a 
source located on the notified owner or operator's site and investigate 
to confirm if a super-emitter emissions event is still ongoing. 
Further, the EPA agrees that a root cause analysis is necessary to 
identify the causes of the super-emitter emissions event. Therefore, we 
are proposing to require owners and operators to initiate a root cause 
analysis to determine the cause of the super-emitter emissions event 
and to take corrective actions to mitigate the emissions. Examples of a 
root cause analysis and corrective action could range from a survey 
using OGI or other technologies combined with repairs of any leaks 
identified, to visual inspections of thief hatches and closing any 
found open or unlatched. As explained in more detail later in this 
section, such corrective actions are tasks that owners and operators 
already would undertake to maintain normal operations. One commenter 
\112\ noted that the investigation may find the emissions are 
attributed to something other than a malfunction or abnormal emission; 
in those cases, the responsive action may only need to include specific 
documentation of the emissions source, such as maintenance activities, 
which should be described in the report.
---------------------------------------------------------------------------

    \112\ See Document ID No. EPA-HQ-OAR-2021-0317-1391.
---------------------------------------------------------------------------

    The EPA is proposing to require initiation of the root cause 
analysis and corrective actions within five calendar days of an owner 
or operator receiving the notification of the super-emitter emissions 
event, and completion of corrective actions within 10 days of the 
notification. Because super-emitter emissions events are such large 
mass emissions rates (100 kg/hr or greater), it is imperative that 
mitigation is achieved in a timely manner. One commenter \113\ 
suggested a program where the investigation would start within 14 days 
of notification, with repairs completed within 30 days of discovery of 
the event. However, the EPA believes that identification of the 
emissions source and remedial action in a much shorter timeframe is 
both warranted and necessary.
---------------------------------------------------------------------------

    \113\ See Document ID No. EPA-HQ-OAR-2021-0317-0832.
---------------------------------------------------------------------------

    Notwithstanding the necessary urgency of mitigating super-emitter 
emissions events, the EPA does recognize that in some cases, 
significant efforts may be required to fully complete required 
mitigation. It is possible that some corrective actions would take 
longer than the proposed 10 days to complete. Therefore, the EPA is 
proposing a requirement for owners and operators to develop and submit 
a corrective action plan that describes the corrective action(s) 
completed to date, additional measures that they propose to employ to 
reduce or eliminate the emissions, and a schedule for completion of 
those measures. This corrective action plan would be due within 30 days 
of receipt of the notification of the super-emitter emissions event. 
This timeframe allows for an additional 20 days beyond the repair 
deadline to draft the corrective action plan and submit it to the 
Agency or delegated state authority.
    Finally, the EPA is proposing to require the submission of a 
written report within 15 days of completing the root cause and 
corrective action to the Agency and delegated state authority. In the 
case of a designated facility covered by a state plan, the EPA solicits 
comment on whether such written report should be sent to the state in 
addition to the EPA. The EPA would promptly post online all reports 
received from the owner-operator in response to a notice of super-
emitter event. This written report would include information such as 
the data included in the notification, the source of the emissions, 
corrective actions taken to mitigate the emissions, and the compliance 
status of the affected facilities. To the extent a deviation or 
potential violation is identified as the root cause of the emissions, 
the owner or operator would report that information. If the operator 
finds that emissions above the super-emitter threshold are not 
occurring, and there is no evidence that they may have occurred as 
reported, then the method for making that determination and the 
evidence in support should be included in the required report to the 
EPA. To the extent an owner or operator determines that the 
notification contains a demonstrable error (e.g., that the notifier was 
not a qualified third party, that the third party did not use the 
appropriate methane detection technology, or that

[[Page 74752]]

the reported emissions event did not exceed the threshold), the report 
would need only include a description of the error and an explanation 
as to why, under these circumstances, a root cause analysis was not 
conducted. The EPA solicits comment on what other elements should be 
included in the owner-operator reports to the state and the EPA.
    The EPA solicits comment on these proposed deadlines for initiating 
the analysis and completion of corrective actions. For comments 
requesting shorter or longer timeframes, we are requesting specific 
examples that would support any changes to this proposal.
b. Statutory Basis of Super-Emitter Program
    There are several ways in which the proposed super-emitter response 
program described above fits within the EPA's authority under section 
111 of the CAA, and two legal frameworks are outlined below.
    First, the EPA could treat a super-emitter emissions event as a 
separate and distinct source of emissions. Under this regulatory 
framework, sources of super-emitter emissions events from unintended 
venting would be an affected facility/designated facility, and the 
super-emitter response program would serve as the standard reflecting 
the BSER for these facilities.
    Specifically, the EPA is proposing a new ``super-emitter'' affected 
facility under NSPS OOOOb (and designated facility under EG OOOOc), 
which the EPA would define as any equipment or control devices, or 
parts thereof, at a well site, centralized production facility, 
compressor station, or natural gas processing plant, that causes a 
super-emitter emissions event (i.e., any emissions detected using 
remote detection methods with a quantified emission rate of 100 kg/hr 
of methane or greater). While the other requirements proposed as part 
of this rulemaking are intended to reduce or eliminate unintentional 
releases, the super-emitter response program is intended as a backstop 
to those provisions, to identify any super-emitter emissions events not 
prevented as a result of other requirements of the proposed rule.
    As discussed above, the EPA believes that super-emitter emissions 
events from unintentional releases tend to occur as a result of 
equipment malfunctions and/or poor operations; therefore, the BSER for 
super-emitter emissions events would be to correct the malfunction or 
operational issues and resume normal operations consistent with the 
standards or requirements applicable to the source(s) of the super-
emitter emissions event in this proposed rule. The November 2021 
proposal and this supplemental proposal contain standards and 
requirements that, if implemented correctly, would prevent or mitigate 
these super-emitter emissions events. For example, if a root cause 
analysis identifies a control device as a source of a super-emitter 
emissions event, then complying with the requirements for that control 
device in this proposed rule would bring such device back to normal 
operation. If the source of a super-emitter emissions event is a 
leaking fugitive emissions component or an open thief hatch, repairing 
the component or ensuring that the thief hatch is closed in accordance 
with the fugitive emissions standards in this proposal would resume 
these components to normal operation. The super-emitter response 
program would require that, where approved, qualified third parties or 
state or Federal governments provide actionable data of known quality 
about a super-emitter event to owners and operators of a super-emitter 
affected facility, and owners and operators would conduct a root-cause 
analysis to identify the sources of the super-emitter emissions and 
take corrective actions to mitigate the problems in order to resume 
normal operation. Because specific corrective actions required to 
resume normal operations would depend on the equipment causing the 
super-emitter emissions event, and because normal operations could 
differ from site to site, the proposed program would allow owners and 
operators to determine the appropriate corrective actions so long as 
the event is mitigated.
    The EPA proposes to determine that these requirements are justified 
as BSER for this proposed super-emitter affected/designated facility 
for several reasons. First, we expect that, as part of normal 
operations, owners and operators should already be correcting equipment 
malfunctions and/or poor operations as such issues arise; therefore, 
costs associated with maintaining normal operations should already be 
accounted for in their operational costs. As mentioned above, the most 
widely known sources of unintended super-emitter emissions events are 
from equipment or control devices that would be subject to emission 
limitations (e.g., 95 percent reduction) or associated compliance 
assurance requirements in the proposed NSPS OOOOb/EG OOOOc. For these 
sources, where a super-emitter emissions event suggests a violation of 
one or more of these standards or requirements, owners and operators 
would already be required to investigate the source of the super-
emitter emissions event to ensure that it is complying with all 
applicable standards and requirements. The proposed super-emitter 
response program would simply require the owner and operator to take 
these same steps upon receiving notice of a super-emitter emissions 
event, provided by a regulatory authority or an EPA approved qualified 
third party, as determined under the proposed program. As explained in 
more detail above, the proposed super-emitter response program would 
include a certification process and other criteria to assure the 
quality and reliability of third-party data regarding a super-emitter 
emissions event. Having established the reliability and quality of the 
third-party data regarding a super-emitter emissions event, it is 
reasonable to require prompt investigation and remediation of the 
emissions. Super-emitter emissions events could also be caused by 
fugitive emissions components that, if persistent, would be detected 
and repaired during the next fugitive monitoring survey; the super-
emitter program would simply make the same repair earlier. There would 
be no associated monitoring cost for owners and operators, as 
monitoring under this program would be conducted by EPA-approved 
qualified third parties. Accordingly, the EPA anticipates that there 
should be no additional cost associated with this work practice 
standard for the super-emitter emissions event affected facility. The 
EPA seeks comment on this issue.
    To the extent there are additional costs associated with the 
investigation or mitigation of these events, the EPA anticipates that 
the costs would be minor in relation to the benefits of stopping such a 
huge emissions event, making them obviously cost-effective, as 
explained below. The EPA proposes that it is reasonable to conclude 
that these actions would be cost effective in light of the large mass 
emissions rate (100 kg/hr of methane or greater) that would be reduced 
and the value of the high volume and value of gas saved by mitigation 
of the event. The EPA finds in the November 2021 proposal and this 
supplemental proposal that some proposed standards are cost effective 
when they result in an expected reduction of about 10 tons of methane 
at a facility over the course of a year. The super-emitters that can be 
identified through the super-emitter response program produce that 
amount of methane in five days or less and the

[[Page 74753]]

remedies are the same or similar.\114\ For example, if the source of a 
super-emitter emissions event is an open thief hatch on a controlled 
tank battery, the first corrective action would be to close the thief 
hatch, which would incur negligible costs. In other words, it is highly 
unlikely that in general these actions would exceed the $2,185/ton of 
methane reduced, which is the highest value we have determined to be 
cost effective for reducing methane in rulemakings addressing methane 
under section 111 of the CAA. The cost effectiveness for responses to 
super-emitter emissions events will usually be substantially below this 
threshold, given that, by definition, super-emitter emissions events 
emit at least one ton of methane every nine hours, and over 18 tons in 
a week. For the reasons stated above, the EPA anticipates that 
requiring immediate corrective actions to resume normal operations to 
eliminate the super-emitter emission event could be achieved at a 
reasonable cost for this proposed affected/designated facility. The EPA 
seeks comment on this conclusion.
---------------------------------------------------------------------------

    \114\ See Table 11, Summary of Emission Reductions and Cost-
Effectiveness: Well Sites with Major Production or Processing 
Equipment, Quarterly Monitoring.
---------------------------------------------------------------------------

    The EPA finds that the above regulatory framework of treating 
super-emitter emissions events from unintended venting as an affected 
facility that would be subject to the super-emitter response program is 
a clear, simple, and straight forward approach for addressing such 
large emission events.
    Second, the super-emitter response program can be justified as part 
of the standards and requirements that apply to individual affected/
designated facilities under this rule, a number of which are known to 
be frequent causes of super-emitter emission events which, as explained 
earlier, may not necessarily be identified and addressed through more 
frequent monitoring that we have determined is not cost-effective. As 
mentioned above, the most widely known sources of unintentional 
releases resulting in super-emitter emissions events are from 
controlled tank batteries, flares, natural gas-driven pneumatic 
controllers, and fugitive emissions, all of which would be either 
affected facilities or designated facilities under the NSPS OOOOb and 
EG OOOOc, respectively, or are control devices used on affected 
facilities/designated facilities for which the proposed rules include 
specific requirements. The EPA proposes to incorporate the super-
emitter program into these standards by considering the super-emitter 
program as: (1) An additional compliance assurance measure, in the case 
of sources that are subject to numerical standards of performance and 
associated control device requirements, and (2) an additional work 
practice standard, in the case of sources for which the EPA is 
proposing work practice standards under this rule. However, despite the 
proposed incorporation, the super-emitter response program is 
nevertheless severable from the standards of performance and work 
practice standards that are being separately established for each of 
the sources addressed in this rule. Each of these other proposed 
standards in this rule reflects the use of a specific emission 
reduction or detection technology or measure that the EPA has 
determined to be BSER for a given emission source after evaluating its 
performance, cost and other factors associated with its use, as 
required by CAA section 111(a) (under the definition of a ``standard of 
performance''). Because whether such technology or measure qualifies as 
the BSER under CAA section 111(a) does not depend on the presence of 
the super-emitter response program, the resulting standards of 
performance and work practice standards proposed in this rulemaking 
would continue to reflect the use of that technology or measure, and in 
turn the BSER, even without the super-emitter response program.
    Compliance assurance. For super-emitter emissions events from 
affected facilities/designated facilities subject to numerical 
standards, the super-emitter response program would serve as an added 
compliance assurance mechanism, aimed at ensuring compliance with the 
numerical emissions standards and associated control device or other 
compliance assurance requirements. Where one of these facilities is 
determined to be the cause of a super-emitter emissions event, it is 
reasonable to assume that the emissions source is out of compliance and 
to require corrective action to bring the facility back into compliance 
with the applicable standard or requirement.
    There are two known sources of unintended venting that could result 
in super-emitter emissions events that would be subject to numerical 
performance standards as affected facilities or designated facilities: 
tank batteries with potential emissions above six tpy of VOC or 20 tpy 
of methane and natural gas-driven pneumatic controllers. Specifically, 
for storage vessel affected facilities/designated facilities, the EPA 
is proposing a numerical standard of performance that would require 
reducing VOC and methane emissions by 95 percent. Where a control 
device is used to meet this standard, the EPA is proposing specific 
compliance assurance measures, such as a requirement that thief hatches 
and other openings remain closed (``closed cover requirements''). As 
discussed in section IV.I of this preamble, the EPA is proposing to 
require quarterly OGI inspections of thief hatches and other openings 
to ensure the closed cover requirement, and in turn the 95 percent 
emission reduction standard, are met. If these standards and 
requirements are rigorously followed, the EPA anticipates that they 
should prevent super-emitter emissions events from controlled storage 
tanks. However, these thief hatches are a commonly known source of 
super-emitter emissions events when they are not closed and properly 
latched. The proposed super-emitter response program would therefore 
serve as a backstop--an additional compliance assurance measure for the 
storage vessels standards--by requiring corrective action where it is 
determined that a super-emitter emissions event was caused (in whole or 
in part) by noncompliant storage vessels. Similarly, with respect to 
natural gas-driven pneumatic controllers, for which the EPA is 
proposing a zero-emissions standard, the EPA is proposing to require 
quarterly OGI inspections of self-contained natural gas-driven 
pneumatic controllers to ensure there are no identifiable emissions 
from the controller as a compliance assurance measure. The super-
emitter response program would serve as an additional compliance 
assurance measure by requiring immediate corrective action where it is 
determined that a super-emitter emissions event was caused (in whole or 
in part) by a natural gas-driven pneumatic controller affected 
facility.
    As mentioned above, flares are also a widely known cause of super-
emitter emissions events. To our knowledge, all flares located at well 
sites, centralized production facilities, compressor stations, or 
natural gas processing plants are (or would be) used to meet a 
performance standard in NSPS OOOOb or EG OOOOc. As such, they would be 
required to meet the design and operation requirements for flares in 
this proposal, such as operation and monitoring for a continuous pilot. 
Flares designed and operated according to the proposed requirements for 
control devices should not cause a super-emitter emissions event. The 
super-

[[Page 74754]]

emitter response program would help assure compliance with these flare 
requirements (and in turn the relevant performance standards) by 
requiring owners and operators to take immediate corrective actions to 
bring that flare into compliance where it is determined that a super-
emitter emissions event is caused by a flare. For these sources, where 
a super-emitter emissions event suggests a violation of one or more of 
these standards or requirements, owners and operators would already be 
required to investigate the source of the super-emitter emissions event 
to ensure that it is complying with all applicable standards and 
requirements. Since the proposed super-emitter response program would 
require these same measures, we do not anticipate additional costs 
associated with the program.
    To the extent there are additional costs associated with the 
investigation or mitigation of these events, the EPA expects that the 
costs would be minor in relation to the benefits of stopping such a 
huge emissions event, making them obviously cost-effective. As 
explained previously in this section, it is reasonable to conclude that 
these actions would be cost effective in light of the large mass 
emissions rate (100 kg/hr of methane or greater) that would be reduced 
and the value of the high volume of gas saved by mitigation of the 
event.
    Work practice standards for detecting and repairing fugitive 
emissions. As discussed above, super-emitter emissions events may also 
occur from fugitive emissions components, which are not subject to 
numerical standards, but rather to a work practice standard that 
requires periodic monitoring (using OGI, AVO, or an advanced 
technology) and repair of emissions that are identified from fugitive 
emissions components. A super-emitter emissions event could occur 
between the required periodic monitoring and thus not be detected and 
repaired until the next periodic monitoring event. In addition, if 
required periodic monitoring is missed, or is not performed well, 
super-emitter emissions events could be occurring that the periodic 
monitoring program fails to identify. For affected facilities and 
designated facilities (i.e., collection of fugitive emissions 
components) subject to the periodic monitoring and repair requirements, 
the super-emitter response program would serve as an additional work 
practice standard that would require corrective action whenever the 
owner or operator is notified of a super-emitter emissions event by an 
EPA, a state, or an approved third party under the super-emitter 
response program, and it is determined that fugitive emissions 
components are (in whole or in part) the source of the event.
    While, as discussed in section IV.A.1, the EPA does not believe it 
is cost-effective to require operators to conduct periodic OGI 
monitoring more frequently than the intervals set out in Section 
IV.A.1, if a super-emitter emissions event is detected by a regulatory 
authority or approved qualified third party in between monitoring 
requirements, the EPA proposes that the BSER include responding to that 
event and addressing the root cause of the super emission.
    The more targeted super-emitter response program would thus be a 
more effective solution for addressing sporadic, large emission events 
that may occur outside the periodic OGI monitoring. The conclusion that 
the super-emitter response program is appropriate for addressing these 
particularly large emissions events does not undermine the EPA's 
determination about the frequency of periodic monitoring otherwise 
required under the fugitive emissions work practice standard. While 
super-emitter emissions events are important to address as a 
significant source of potential emission reductions, these events do 
not occur regularly across all well sites and are not predictable. 
Accordingly, while the periodic monitoring is appropriate to address 
more routine leak detection and repair, and to help prevent the 
occurrence of super-emitter emissions events, the super-emitter 
response program will help ensure that the unpredictable but 
potentially significant super-emitter emissions events are 
expeditiously addressed.
    Further, the corrective action to mitigate a super-emitter 
emissions event from this source has the potential to result in 
significant emissions reductions earlier than would have been achieved 
by the periodic monitoring requirements. The EPA therefore believes 
that the super-emitter response program is a reasonable addition as 
part of the BSER for fugitive components because the program would only 
target particularly large emission events (measuring over 100 kg/hr) 
from these affected or designated facilities and would not require any 
action for smaller emissions events that would be addressed by the 
periodic monitoring.
    We have considered the costs of adding the super-emitter response 
program as an additional work practice standard to the periodic 
monitoring and repair requirements for addressing fugitive emissions 
and concluded that the cost is reasonable. First, owners and operators 
do not bear the cost of monitoring and detecting super-emitter 
emissions events, which would be conducted by EPA-approved qualified 
third parties. Instead, as discussed in more detail below, the first 
step of the program would be for owners and operators to investigate 
and identify the source(s) of a super-emitter emissions event upon 
receiving reliable information. Since owners and operators would 
already have to perform this task for purposes of the compliance 
assurance measure for other affected facilities and associated control 
devices under the super-emitter response program, described above, 
there would be little additional cost in including this same root-cause 
analysis as part of the fugitive emissions work practice standards. 
Second, to the extent a root-cause analysis reveals that the super-
emitter emissions event is caused by a fugitive emissions component, 
there may be no additional cost associated with their repair, since 
these fugitive emissions might be detected and repaired during the next 
scheduled periodic monitoring; the super-emitter response program would 
simply require such repair to occur sooner. In other words, for super-
emitter emissions events identified as resulting from fugitive 
emissions components between scheduled monitoring surveys, the proposed 
super-emitter response program would provide an opportunity for repairs 
sooner than the next scheduled survey, thus resulting in fewer 
emissions overall from the event.
    Moreover, even if there are costs associated with the investigation 
and mitigation, the threshold for identifying a super-emitter emissions 
event is so high that it ensures that the emissions reductions achieved 
by the mitigation are cost-effective. In other words, it is reasonable 
to conclude that these actions would be cost-effective in light of the 
large mass rate of emissions (100 kg/hr of methane or greater) that 
would be reduced, and the high volume of gas saved. It is highly 
unlikely that these actions would exceed the $2,185/ton of methane 
reduced, which is the highest value we have determined to be cost 
effective for reducing methane from sources within this source 
category.
    In summary, the EPA finds the data demonstrate that the super-
emitter response program is cost-effective, even though the EPA 
recognizes that the total emissions reductions that will result from 
the program are difficult to quantify. By definition, a super-emitter 
emissions event emits more than 100 kg of methane/hour, which means 
that an on-going super-emitter emissions event that lasts an extended 
period may emit

[[Page 74755]]

more than 2.5 tons of methane in a day, and potentially almost 80 tons 
if it continued undetected for a month. Applying the same social cost 
of methane values used to develop the estimates in Table 5 above, such 
an event could generate over $100,000 in avoidable climate 
damages.\115\ The proposed fugitive emissions monitoring and repair 
requirements for facilities with major production and processing 
equipment, discussed in section IV.A, are cost-effective when they are 
projected to reduce 10.85 tpy of methane. A super-emitter emissions 
event may emit almost twice that, or in some cases substantially more, 
in a single week. In addition, the cost of most of the repairs that 
would be necessary to respond to a super-emitter emissions event may be 
achieved at very low additional cost because the need for repair would 
be discovered at the next required inspection, indicating that most 
repairs in response to super-emitter emissions events may be simply 
moving the repairs earlier in time. Furthermore, halting super-emitter 
emissions events recovers natural gas for sale that would otherwise be 
emitted to the atmosphere, so it is possible that for many super-
emitter emissions events identified, the revenues from recovered 
natural gas may offset a significant portion of the costs of repair 
incurred by the owner or operator. For all these reasons, the EPA finds 
the super-emitter response program cost-effective. Because the costs of 
this program incurred by owners and operators, the length of time over 
which these events occur, and the emissions reductions that may be 
achieved have uncertainties associated with them, the EPA solicits 
comments on the various factors related to the cost-effectiveness of 
the super-emitter response program, including any information further 
detailing the costs and emissions reductions of this program. 
Specifically, the EPA solicits comments on any relevant data, 
appropriate methodologies, or reliable estimates to help quantify the 
costs, emissions reductions, benefits, and potential distributional 
effects of this program (including, for example, benefits for 
communities with EJ concerns). We also take comment on how to improve 
the accuracy of our estimates of baseline emissions levels, emissions 
reduction opportunities, and the frequency and intensity of super-
emitter events, and how to incorporate any recent, reliable estimates 
of methane emissions.
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    \115\ This damage estimate assumes a social cost of methane 
estimate of at least $1,400 per metric ton of methane, which is less 
than the interim estimate that EPA uses in the RIA for a 3% discount 
rate for the first year that the proposed NSPS OOOOb is assumed to 
go into effect (2023).
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c. Additional Solicitations for Comment
    While the EPA is proposing a general framework for the super-
emitter response program, there are several additional aspects of the 
program for which we are soliciting additional information and comment. 
These solicitations are described in the following paragraphs.
    First, the EPA is soliciting comment on the mechanism for 
identifying the owners and operators to receive the super-emitter 
emissions event notifications. Entities approved to make such 
notifications need a way to identify to whom they should be sent and 
how to assure they are received. The EPA specifically seeks comment on 
what mechanisms exist to make such identifications now, the 
reliability, accuracy, and timeliness of those mechanisms, and the 
difficulty or cost of accessing those mechanisms.
    The EPA is also soliciting comment on the amount of time allowed 
for notifications following detection of a super-emitter emissions 
event. Clearly, timely notification of the event is essential to 
maximize the emission reduction potential from the event, but it is the 
EPA's understanding that each technology or remote measurement method 
experiences a lag between when a survey is conducted and when the data 
has been analyzed to demonstrate emissions were present. The EPA is 
soliciting comment on what deadline for notifications following 
detection survey is most advantageous and feasible given current data 
analysis requirements for remote measurement technologies and methods. 
Further, time will be required to properly identify the relevant owner 
or operator of the site. One factor is that ownership of sites can 
change frequently, or specific contacts may move into other roles or 
leave the company. Therefore, the EPA is soliciting comment on the 
amount of additional time that should be factored into the notification 
process to account for this identification step.

D. Pneumatic Controllers

    Pneumatic controllers are devices used to regulate a variety of 
physical parameters, or process variables, often 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. Detailed information on pneumatic controllers, 
including their functions, operations, and emissions, is provided in 
the preamble for the November 2021 proposal (86 FR 63202-63203; 
November 15, 2021).
1. NSPS OOOOb
a. November 2021 Proposal
    In the November 2021 proposal, a pneumatic controller affected 
facility was defined as each single natural gas-driven pneumatic 
controller, whether the controller was a continuous bleed controller or 
an intermittent vent controller. This affected facility definition 
would have applied at sites in all segments of the oil and natural gas 
source category. We proposed the requirement that all controllers 
(continuous bleed and intermittent vent) have a VOC and methane 
emission rate of zero. The proposed rule did not specify how this 
emission rate of zero was to be achieved, but a variety of viable 
options were discussed. These options included the use of pneumatic 
controllers that are not driven by natural gas such as instrument air-
driven pneumatic controllers and electric controllers, as well as 
natural gas-driven controllers that are designed so that there are no 
emissions, such as self-contained pneumatic controllers. Because we 
proposed to define an affected facility as each pneumatic controller 
that is driven by natural gas and that emits to the atmosphere, 
pneumatic controllers not driven by natural gas would not have been 
affected facilities. Controllers that are driven by natural gas but 
that do not emit to the atmosphere would not have been affected 
facilities either, according to the November 2021 proposed definition.
    The November 2021 proposed rule included an exemption from this 
zero-emission standard for pneumatic controllers at sites in Alaska 
that do not have access to electrical power. For these sites, the 
proposed rule would have required the use of low-bleed, continuous 
bleed controllers. It would also have required that intermittent vent 
controllers not vent during idle periods and that periodic inspections 
be performed on these controllers to ensure that such venting does not 
occur.

[[Page 74756]]

b. Changes to Proposal and Rationale
    The proposed NSPS OOOOb requirements in this supplemental proposal 
differ from the November 2021 proposal in several ways, starting with 
the affected facility definition. As noted above, the pneumatic 
controller affected facility definition proposed in November 2021 was 
each individual natural gas-driven pneumatic controller. In this 
supplemental proposal, a pneumatic controller affected facility is 
defined as the collection of all the natural gas-driven pneumatic 
controllers at a site.
    Another change from the November 2021 proposal is that two specific 
types of natural gas-driven controllers that were proposed to be 
excluded from the affected facility definition are now proposed to be 
included. These are: (1) Controllers where the emissions are collected 
and routed to a gas-gathering flow line or collection system to a sales 
line, used as an onsite fuel source, or used for another useful purpose 
that a purchased fuel or raw material would serve (i.e., generally 
characterized as ``routing to a process''); and (2) self-contained 
natural gas pneumatic controllers.
    There is no change to the fundamental proposed standard for 
pneumatic controllers, which is that all pneumatic controllers would be 
required to have a methane and VOC emission rate of zero. The proposed 
standard does include requirements for the two specific types of 
natural gas-driven controllers identified above. These controllers do 
not emit methane or VOC from routine operations. However, since they 
are powered by natural gas, the potential for emissions exists if they 
are not maintained and operated properly. For instance, a self-
contained controller could malfunction or develop leaks, or a CVS that 
is routing the controller emissions to a process could develop leaks. 
Therefore, the proposed rule includes requirements to avoid such 
situations so that the controllers have zero direct emissions. Since 
routing to a process includes the option of using the natural gas 
captured for use as a fuel source, emissions would occur downstream at 
the engine, generator, or process heater resulting from the combustion 
of the natural gas from the controllers. However, these emissions are 
replacing those that would have resulted from the combustion of fuel 
gas, meaning that the net result is still zero direct emissions.
    While the BSER conclusion did not change from the November 2021 
analysis, the EPA did update the analysis based on information received 
in the public comments, including an analysis of potential alternative 
standards for small sites with few pneumatic controllers.
    Details on the proposed pneumatic controller requirements in this 
supplemental proposal are provided below in section IV.D.1.c. The 
following sections provide the rationale for the changes discussed 
above, a discussion of other related issues raised by commenters, and 
the updated BSER analysis.
i. Affected Facility, Modification, and Reconstruction
    As noted above, the pneumatic controller affected facility 
definition changed from being based on a single continuous bleed or 
intermittent vent controller in the November 2021 proposal to the 
collection of natural gas-driven continuous bleed and intermittent vent 
controllers at a site in this supplemental proposal.\116\ The EPA is 
proposing this change based on the consistent recommendation of 
numerous commenters, particularly commenters from the oil and natural 
gas industry. Several comments on the November 2021 proposal noted the 
disconnect between the pneumatic controller affected facility 
definition (i.e., an individual controller) and the cost analysis, 
which was based on the replacement of all pneumatic controllers with 
zero-emitting devices at a site.\117\ One commenter pointed out the 
complexities of tracking and managing the universe of pneumatic 
controllers at a site when some are affected facilities and others are 
not, and recommended that the EPA propose a simpler and more robust 
system.\118\ Another commenter indicated that defining the affected 
facility on a site-wide basis aligns with how emissions from pneumatic 
controllers will likely be handled by owners and operators of oil and 
natural gas facilities. This commenter opined that defining the 
pneumatic controller affected facility on a single controller basis, as 
opposed to as the collection of all controllers at a site, would be 
unnecessarily burdensome.\119\ A separate commenter discusses the fact 
that converting a single pneumatic controller to a zero-emitting device 
typically requires a conversion of all controllers at the facility to 
zero-emitting devices.\120\
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    \116\ The EPA notes that there are other sources of emissions in 
this supplemental proposed rule that the EPA proposes to regulate as 
a collection of emissions sources, rather than as individual 
emission units. Namely, the EPA proposes to define tank batteries as 
the group of all storage vessels that are manifolded together for 
liquid transfer and proposes to define fugitive emissions components 
as the collection of fugitive emissions components at all well 
sites.
    \117\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0599, EPA-HQ-
OAR-2021-0317-0808, EPA-HQ-OAR-2021-0317-0831, and EPA-HQ-OAR-2021-
0317-0777.
    \118\ See Document ID No. EPA-HQ-OAR-2021-0317-0742.
    \119\ See Document ID No. EPA-HQ-OAR-2021-0317-0817.
    \120\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0808.
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    We agree with the commenters that defining the pneumatic controller 
affected facility as the collection of all controllers at a site is the 
most practical approach. Significantly, most of the zero-emissions 
measures for pneumatic controllers are site-wide solutions. For 
instance, a compressed air system installed at a site would be used to 
power all of the pneumatic controllers at the site, rather than a 
separate system for each controller. Similarly, a solution based on 
solar energy would likely utilize a single array of solar panels to 
provide power to all the controllers at the site. In fact, as pointed 
out by the commenters, the analysis for the November 2021 proposed rule 
was conducted on a ``model plant'' site-wide basis. As noted above, the 
comments that the EPA received on the pneumatic controller affected 
facility definition in the November 2021 proposal all advocated for a 
change in the definition from a single controller to the collection of 
all onsite pneumatic controllers. However, the EPA did not specifically 
solicit comment on the particular question of how to define the 
affected facility in November. Now that the EPA is proposing in this 
supplemental proposal to define the affected facility as the collection 
of natural gas-driven continuous bleed and intermittent vent 
controllers at a site, the EPA solicits comment on the proposed changed 
definition.
    Under the previous approach of treating each controller on an 
individual basis, the installation or replacement of a pneumatic 
controller would have resulted in that singular controller being a new 
source and an affected facility subject to NSPS OOOOb. Under this 
supplemental proposal approach to treat the collection of all 
controllers at a site as the affected facility, clear descriptions of 
modification and reconstruction are needed in order to indicate when an 
existing collection of controllers would become subject to NSPS OOOOb. 
In 40 CFR 60.14(a), a ``modification'' is defined as ``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 clarify 
what constitutes a modification for the

[[Page 74757]]

collection of all controllers at a site, the supplemental proposed rule 
specifies that if one or more pneumatic controllers is added to the 
site, such addition constitutes a modification and the collection of 
pneumatic controllers at the site becomes a pneumatic controller 
affected facility. This is because the addition of a controller 
represents a physical change to the site and would result in an 
increase in emissions from the collection of controllers. Based on 
information provided by industry commenters, the EPA believes that 
owners and operators will implement zero-emissions controllers across a 
site when a modification occurs because converting a single pneumatic 
controller to a zero-emitting device typically requires converting all 
controllers at the facility to zero-emitting devices. The EPA solicits 
comment on the ways in which a modification to a pneumatic controller 
affected facility would occur in light of the affected facility 
definition proposed herein, which includes the collection of all 
natural gas-driven continuous bleed and intermittent vent controllers 
at a site.
    In 40 CFR 60.15(b), ``reconstruction'' is defined as the 
replacement of components of an existing facility ``to such an extent 
that the fixed capital cost of the new components exceeds 50 percent of 
the fixed capital cost that would be required to construct a comparable 
entirely new facility,'' and ``it is technologically and economically 
feasible to meet the applicable standards.'' The proposed pneumatic 
controller affected facility definition for this supplemental proposal 
is the collection of all natural gas driven controllers at a site; 
therefore, the cost that would be required to construct a ``comparable 
entirely new facility'' would be the cost of replacing all existing 
controllers with new controllers. Because individual controllers are 
likely to have comparable replacement costs, it is reasonable to assume 
that there would be a one-to-one correlation between the percentage of 
controllers being replaced at a site and the percentage of the fixed 
capital cost that would be required to construct a comparable entirely 
new facility. Accordingly, we are proposing to include a second, 
simplified method of determining whether a controller replacement 
project constitutes reconstruction under 40 CFR 60.15(b)(1) whereby 
reconstruction may be considered to occur whenever greater than 50 
percent of the number of existing onsite controllers are replaced.\121\ 
The EPA believes that allowing owners or operators to determine 
reconstruction by counting the number of controllers replaced is a more 
straightforward option than requiring owners and operators to provide 
cost estimate information. By providing this option, the EPA intends to 
reduce the administrative burden on owners and operators, as well as on 
the implementing agency reviewing the information. Owners and operators 
would be able to choose whether to use the cost-based criterion or the 
proposed number-of-controllers criterion. No matter which option an 
owner or operator chooses to use, the remaining provisions of 40 CFR 
60.15 apply--namely, 40 CFR 60.15(a), the technological and economical 
provision of 40 CFR 60.15(b)(2), and the requirements for notification 
to the Administrator and a determination by the Administrator in 40 CFR 
60.15(d), (e) and (f). The EPA is proposing that the standard in 40 CFR 
60.15(b)(1) specifying that the ``fixed capital cost of the new 
components exceeds 50 percent of the fixed capital cost that would be 
required to construct a comparable entirely new facility'' can be met 
through a showing that more than 50 percent of the number of existing 
onsite controllers are replaced. Therefore, upon such a showing, an 
owner or operator may demonstrate compliance with the remaining 
provisions of 40 CFR 60.15 that reference the ``fixed capital cost'' 
criterion. The EPA solicits comment on its proposal to add an option 
for owners or operators to use in determining whether reconstruction 
occurs by showing the number of components replaced. The EPA reiterates 
that this proposed option would supplement the existing option of 
determining replacements by fixed capital cost, as set forth in 40 CFR 
60.15.
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    \121\ Adding this method of determining ``reconstruction'' for 
pneumatic controllers is in accordance with 40 CFR 60.15(g), which 
states that ``[i]ndividual subparts of this part 
[``Reconstruction''] may include specific provisions which refine 
and delimit the concept of reconstruction set forth in this 
section.''
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    A second factor for consideration in the reconstruction of an 
existing pneumatic controller affected facility is during what time 
period the number of controllers replaced or the fixed capital cost of 
the new components should be aggregated. Consider the following 
scenario: an owner first seeks to replace 30 percent of the pneumatic 
controllers of an existing facility and then, shortly after commencing 
or completing those replacements, the owner seeks to replace an 
additional 30 percent. The owner would have replaced 60 percent of its 
controllers in total, and presumably, the fixed capital cost of those 
two replacement programs would be approximately 60 percent of the fixed 
capital cost that would be required to construct a comparable entirely 
new facility. It is unclear under the language of 40 CFR 60.15(d) 
whether this owner should be deemed to have proposed two distinct 
replacement programs or instead a single replacement program. The EPA 
believes that such a stepwise controller replacement program should not 
be used by facilities undergoing numerous replacement programs close in 
time to avoid compliance with the NSPS. Failure to regulate these 
sources would undermine Congress' intent that air quality be enhanced 
over the long term with the turnover of polluting equipment, and with 
the intent of the EPA's reconstruction provisions, which are triggered 
where an existing facility replaces its components ``to such an extent 
that it is technologically and economically feasible for the 
reconstructed facility to comply with the applicable standard of 
performance.'' \122\ Where a number of controllers are replaced 
relatively close in time such that the aggregate costs or number of 
controllers is greater than 50 percent, the EPA proposes to conclude 
that it is reasonable to treat those replacements as part of a 
continuous program of controller replacement for purpose of determining 
reconstruction.
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    \122\ See Modification, Notification, and Reconstruction, 40 FR 
58,417 (December 16, 1975) (also stating that ``the purpose of the 
reconstruction provision is to recognize that replacement of many of 
the components of a facility can be substantially equivalent to 
totally replacing it at the end of its useful life with a newly 
constructed affected facility.'').
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    In order to clarify how the regulatory language in 40 CFR 60.15 
would apply to the replacement of pneumatic controllers, we are 
proposing that where an owner or operator applies the definition of 
reconstruction in Sec.  60.15(b)(1), reconstruction occurs when the 
fixed capital cost of the new pneumatic controllers exceeds 50 percent 
of the fixed capital cost that would be required to replace all the 
pneumatic controllers at the site. The ``fixed capital cost of the new 
pneumatic controllers'' includes the fixed capital cost of all 
pneumatic controllers which are or will be replaced pursuant to all 
continuous programs of component replacement which are commenced within 
any 2-year rolling period.\123\

[[Page 74758]]

Thus, the EPA will count toward the greater than 50 percent 
reconstruction threshold all controllers replaced pursuant to all 
continuous programs of controller replacement which commence within any 
2-year rolling period following proposal of these standards. If the 
owner or operator applies the definition of reconstruction based on the 
percentage of pneumatic controllers replaced, reconstruction occurs 
when greater than 50 percent of the pneumatic controllers at a site are 
replaced. The percentage includes all pneumatic controllers which are 
or will be replaced pursuant to all continuous programs of pneumatic 
controller replacement which are commenced within any 2-year rolling 
period.
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    \123\ As noted above, incorporating a set period of time within 
which numerous component replacements amount to ``reconstruction'' 
is in accordance with 40 CFR 60.15(g), which provides that 
``[i]ndividual subparts of this part [``Reconstruction''] may 
include specific provisions which refine and delimit the concept of 
reconstruction set forth in this section.'' In addition, the EPA 
notes that numerous NSPS and EG regulatory provisions incorporate a 
2-year time period into the definition of reconstruction. See, e.g., 
Standards of Performance for New Stationary Sources; Bulk Gasoline 
Terminals, 48 FR 37582-83 (August 18, 1983) (explaining need for a 
fixed period within which to determine reconstruction when component 
replacement occurs over time and determining that two years is 
reasonable); 40 CFR 60.506(b) (codifying reconstruction definition 
to include such a time period for bulk gasoline terminals (40 CFR 
part 60, subpart XX)). See also 40 CFR 60.383(b) (metallic mineral 
processing plants (subpart LL)); 40 CFR 60.100(f), 60.100a(d) 
(petroleum refineries (40 CFR part 60, subparts J and Ja)); 40 CFR 
60.706(a) (volatile organic compound emissions from synthetic 
organic chemical manufacturing industry reactor processes (40 CFR 
part 60, subpart RRR)).
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    In the Administrator's judgment, the 2-year rolling period provides 
a reasonable method of determining whether an owner of an oil and 
natural gas site with pneumatic controllers is actually proposing 
extensive controller replacement, within the EPA's original intent in 
promulgating 40 CFR 60.15. The EPA solicits comment on this proposed 2-
year rolling aggregation period for all continuous programs of 
pneumatic controller and pneumatic pump replacement (see section 
IV.E.b.i. for a discussion of proposing the same approach for 
determining reconstruction for pneumatic pumps). The EPA is 
particularly interested in comments regarding whether this approach 
will make it easier for owners and operators to determine 
reconstruction at their sites, whether using a set time frame is 
reasonable and feasible to put into practice, whether two years is an 
appropriate timeframe, and whether a rolling basis for the two-year 
time frame is a reasonable calculation (for example, see Scenario 5 
below). The EPA is also interested in understanding how frequently 
controllers and pumps are typically replaced.
    The following are example scenarios of the application of these 
proposed requirements for a site with 15 natural gas-driven pneumatic 
controllers. Scenario 1: One of the controllers is to be replaced (at 
any given time). The collection of controllers at the site would not 
become a pneumatic controller affected facility because the emissions 
from the collection of controllers would not be increased (so such 
action does not constitute a modification). Also, such action would not 
constitute reconstruction because the fixed capital cost of the 
replacement of this single controller would not equal 50 percent or 
greater of the fixed capital cost that would be required to replace all 
the controllers in the affected facility. Scenario 2: Eight of the 
controllers are to be replaced at the same time. This would represent 
reconstruction (because more than 50 percent of the total are being 
replaced which means that the fixed capital cost of the replacement 
would exceed 50 percent of the fixed capital cost that would be 
required to replace all the controllers in the affected facility), so 
the 15 controllers (i.e., the ``collection'' of controllers at the 
site) would become a pneumatic controller affected facility. This 
affected facility would then be subject to the zero-emissions standard, 
meaning that all controllers at the site, including the eight new 
controllers and the seven existing controllers, must comply with a 
methane and VOC emission rate of zero. Scenario 3--six of the pneumatic 
controllers are replaced in January and seven more controllers are 
replaced the following April (15 months later). This would represent 
reconstruction because more than 50 percent of the total number of 
controllers are being replaced over a 2-year period, so the 15 
controllers (i.e., the ``collection'' of controllers at the site) would 
become a pneumatic controller affected facility at the time the seven 
controllers were replaced in April. This affected facility would then 
be subject to the zero-emissions standard, meaning that all controllers 
at the site must comply with a methane and VOC emission rate of zero. 
Scenario 4: An additional pneumatic controller is added at any given 
time. This would represent a modification since it would constitute a 
physical change and would result in an increase in emissions. The 16 
controllers would represent a pneumatic controller affected facility 
and all would need to comply with a methane and VOC emission rate of 
zero. Scenario 5: replacement of four of the pneumatic controllers is 
commenced in January in year 1; replacement of two more controllers is 
commenced the following April in year 2 (15 months later); replacement 
of two more is commenced the following March in year 3 (26 months after 
the initiating replacement in January); and replacement of four more is 
commenced that August of year 3 (31 months after initiating replacement 
in January). Only six controllers of the 15 controllers were replaced 
in the discrete two-year time period that began in January of year 1, 
and therefore would not meet the proposed reconstruction definition. 
However, when considered on a rolling 2-year basis, eight of the 15 
controllers were replaced over years 2 and 3, which would meet the 
proposed reconstruction definition. EPA specifically solicits comment 
on whether the two-year time frame should be implemented on a rolling 
basis or as a discrete time period.
    The EPA also solicits comment on whether it would be appropriate to 
apply either of the two elements of reconstruction that the EPA is 
proposing for pneumatic controllers (and pneumatic pumps, as described 
in section IV.E.) to any other affected facility in NSPS OOOOb and EG 
OOOOc. Specifically, the EPA is interested in comments regarding 
whether any other source category would benefit from either: 1) adding 
an option to determine reconstruction based on the number of components 
replaced (in addition to the existing option of determining 
replacements by fixed capital cost, as set forth in 40 CFR 60.15), and/
or 2) setting a specific time period within which replaced components 
will be aggregated toward the greater than 50 percent replacement 
threshold (assessed either by number or cost), e.g., any two-year 
period beginning when a continuous program of component replacement 
commences.
    Commenters stated that the EPA should allow like-kind replacement 
of existing individual controllers without causing the controller to 
become an affected facility under NSPS OOOOb.\124\ The commenters 
indicated that if the EPA were to not allow this, operators who are 
voluntarily replacing high-bleed natural gas-driven controllers with 
low-bleed controllers would likely stop doing so. The EPA's proposed 
change to a site-wide pneumatic controller affected facility definition 
would allow the replacement of existing high-bleed controllers with 
low-bleed controllers without becoming an affected facility, provided 
that 50

[[Page 74759]]

percent or less of the controllers are replaced at the same time.
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    \124\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0817 and EPA-HQ-
OAR-2021-0317-0831.
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    Commenters also encouraged the EPA to provide an exemption for 
``temporary sources.'' One commenter provided the example where an 
operation may require use of temporary or portable equipment for a 
short period of time (i.e., less than 180 days) where it may not be 
possible to connect to the grid or route to an onsite control 
device.\125\ Another commenter indicated that non-emitting \126\ 
requirements are not justified for short term controller usage related 
to a non-stationary source, and exemption of controllers on temporary 
equipment is consistent with state regulations proposed in New Mexico 
and finalized in Colorado. The commenter indicated that the EPA should 
also make it clear that the requirements for pneumatic controllers are 
not applicable during drilling or completion.\127\
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    \125\ See Document ID No. EPA-HQ-OAR-2021-0317-0831.
    \126\ The terms ``zero emissions'' and ``non-emitting'' are used 
to describe pneumatic controllers. In Colorado, 5 Code of Colorado 
Regulations (CCR) Regulation 7, Part D, Section III, defines a 
``non-emitting'' controller as ``a device that monitors a process 
parameter such as liquid level, pressure or temperature and sends a 
signal to a control valve in order to control the process parameter 
and does not emit natural gas to the atmosphere. Examples of non-
emitting controllers include but are not limited to: no-bleed 
pneumatic controllers, electric controllers, mechanical controllers 
and routed pneumatic controllers.'' A routed pneumatic controller is 
defined as ``a pneumatic controller that releases natural gas to a 
process, sales line or to a combustion device instead of directly to 
the atmosphere.'' The EPA is proposing that pneumatic controllers 
must be ``zero emission'' controllers. The difference in non-
emitting, as defined by Colorado and as used by the commenter, and 
zero emissions, as proposed in this action, is that pneumatic 
controllers for which emissions are captured and routed to a 
combustion device are not considered to be ``zero emission'' 
controllers. Therefore, routing to a combustion device is not an 
option for compliance with the proposed NSPS OOOOb.
    \127\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.
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    The EPA acknowledges that the focus of the BSER analysis has been 
on stationary sources and pneumatic controllers that are part of the 
routine operation of oil and natural gas facilities. Although some type 
of alternative approach may be warranted for pneumatic controllers 
associated with temporary operations, we lack sufficient information to 
include an exemption, or perhaps alternative standards, for pneumatic 
controllers associated with temporary equipment. Therefore, the EPA is 
requesting more information on these situations. The EPA would like 
specific examples of when temporary equipment is utilized, the function 
of the controllers during this time, how they are powered, and the 
typical duration of their usage. The EPA also requests information 
explaining in detail why the zero-emission solutions that are used for 
the permanent equipment at the site cannot be also utilized for this 
temporary equipment.
    Another change to the affected facility definition in this 
supplemental proposal is that natural gas-driven controllers from which 
all emissions are collected and routed to a process, as well as self-
contained natural gas-driven pneumatic controllers, are not excluded 
from the pneumatic controller affected facility definition. The EPA is 
proposing to include these types of natural gas driven controllers 
because they are driven by natural gas. While the EPA understands that 
these controllers have zero routine emissions from the operation of the 
device and are therefore compliant with the proposed standard when they 
are properly operated and maintained, they do have the potential to 
emit methane and VOC if they are not operated and maintained properly. 
Therefore, we are proposing that natural gas-driven controllers from 
which all emissions are collected and routed to a process, as well as 
self-contained natural gas-driven pneumatic controllers (which release 
gas into the downstream piping and not to the atmosphere), are part of 
a pneumatic controller affected facility, and therefore subject to the 
zero methane and VOC emissions standards. Specifically, the proposed 
rule would require that owners and operators ensure proper maintenance 
and operation of the controllers. For natural gas-driven controllers 
from which all emissions are collected and routed to a process, the CVS 
collecting and routing the emissions to the process must comply with 
the CVS no identifiable emissions requirements in proposed 40 CFR 
60.5411b, paragraphs (a) and (c). Self-contained controllers would be 
required to be designed and operated with no identifiable emissions, as 
demonstrated by initial and quarterly inspections using optical gas 
imaging and any necessary corrective actions.
    NSPS OOOOa exempts controllers from the standards for functional 
needs, ``including but not limited to response time, safety, and 
positive actuation.'' 40 CFR 60.6390a(a). The November 2021 proposed 
rule did not include these functional needs exemptions, except for 
locations in Alaska that did not have access to electrical power. The 
NSPS OOOOa exemptions were based on the use of a low-bleed natural gas 
driven pneumatic controller. Because the November 2021 proposed 
standard would not have allowed the use of natural-gas driven 
controllers, the EPA did not believe that this exemption was needed.
    Several commenters requested that the NSPS OOOOa functional needs 
exemptions be included in NSPS OOOOb in their entirety, while other 
commenters indicated that they should only be allowed in very limited 
instances and only when justification is provided in an annual report. 
Commenters consistently raised the need to utilize natural gas-driven 
pneumatic controllers associated with emergency shutdown devices 
(ESDs). One commenter explained that an ESD is designed to minimize 
consequences of emergency situations and will only emit in certain 
isolated circumstances, such as if a well must be shut in. A large 
change in pressure is required to actuate an ESD, which may not be 
deliverable in a sufficient time by a compressed air or electric 
controller. Furthermore, if power is lost, these devices must still be 
able to function. It is rare that ESDs are activated, and their 
emissions impact is minimal, but their functional need is necessary and 
critical to safe operations. The commenter noted that both the current 
version of the proposed rule in New Mexico and finalized regulations in 
Colorado offer similar exemptions for ESDs.\128\
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    \128\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.
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    The EPA still believes that the overall functional needs exemption 
is not necessary, as the limitations inherent in low-bleed natural gas-
driven controllers are not present in many of the zero emissions 
options, particularly compressed air. The EPA also notes that any 
natural gas-driven controller is allowed, whether low or high-bleed, if 
the emissions are collected and routed to process in a manner that 
achieves zero methane emissions.
    The EPA recognizes the important function of natural gas-driven 
controllers for ESDs. Rather than including such devices in the 
affected facility, the EPA is proposing to specifically exclude them 
from the affected facility definition.
    Relatedly, one commenter requested that the EPA allow companies the 
option to continue to use, or install, a dual natural gas system as a 
backup for key controller functions. Such a natural gas backup system 
would be used in the case of electrically actuated controller failure, 
loss of power, or other contingencies.\129\ Another commenter added 
that if the zero-emissions system (i.e., instrument air) goes down, 
there is no provision within the proposed rule

[[Page 74760]]

to allow for the temporary use of natural gas. The commenter urged the 
EPA to evaluate the reliability and availability of such systems that 
would be deployed at such breadth.\130\ The EPA is interested in 
understanding these backup systems more fully. In particular, the EPA 
is requesting information on these systems regarding how frequently and 
for how long these systems are used or would be expected to be used. 
The EPA is concerned that allowing these backup systems would result in 
a potential loophole that would enable owners or operators to continue 
to use natural gas-driven controllers in routine situations. Therefore, 
the EPA is interested in how the use of these systems could be narrowly 
defined and how a clear distinction could be drawn between the allowed 
use of these backup systems and violations of the zero emissions 
standard.
---------------------------------------------------------------------------

    \129\ See Document ID No. EPA-HQ-OAR-2021-0317-0817.
    \130\ See Document ID No. EPA-HQ-OAR-2021-0317-0599.
---------------------------------------------------------------------------

ii. BSER Analysis
    Based on comments received on the November 2021 BSER analysis and 
updated information provided, the EPA revised the BSER analyses for 
this supplemental proposal for pneumatic controllers for the production 
and transmission and storage segments of the industry. The following 
paragraphs describe the updated information, the changes to the BSER 
analyses, and the updated results. The analysis for natural gas 
processing plants, which can be found in the TSD for the November 2021 
proposal, was not updated.
    Several commenters objected to the emission factors that were used 
for the analysis. One commenter stated that the emission factors used 
in the GHGRP petroleum and natural gas source category (40 CFR part 98, 
subpart W, also referred to as ``GHGRP subpart W'') for pneumatic 
controllers were developed in the 1990's and that they may no longer be 
applicable considering technological improvements.\131\ Another 
commenter indicated that the factors used underestimated emissions and 
that recent research indicates that actual average emissions from 
pneumatic controllers may be higher than estimated.\132\
---------------------------------------------------------------------------

    \131\ See Document ID No. EPA-HQ-OAR-2021-0317-0749.
    \132\ See Document ID No. EPA-HQ-OAR-2021-0317-0918.
---------------------------------------------------------------------------

    The emissions factors used for the November 2021 BSER analysis for 
the production segment were from a recent study conducted by the 
American Petroleum Institute (API).\133\ The factors for the 
transmission and storage segment were from Table W-3B of GHGRP subpart 
W (2021). Since the November 2021 proposal, the EPA has conducted a 
comprehensive review of available information related to emissions from 
natural gas-driven pneumatic controllers and has proposed to update the 
emission factors in GHGRP subpart W to reflect this research (87 FR 
36920; June 21, 2022). The EPA concluded that these results are the 
most appropriate for use in this BSER analysis. The information 
evaluated for the June 2022 proposed revisions to GHGRP subpart W 
included the API study. Table 22 provides the emission factors used for 
the November 2021 analysis and those used for the updated analysis in 
this supplemental proposal.
---------------------------------------------------------------------------

    \133\ ``API Field Measurement Study: Pneumatic Controllers EPA 
Stakeholder Workshop on Oil and Gas.'' November 7, 2019--Pittsburg 
PA. Paul Tupper.

 Table 22--Natural Gas-Driven Pneumatic Controller Emission Factors for
          the Production and Transmission and Storage Segments
------------------------------------------------------------------------
                                         Emissions (scf whole gas/hr)
                                     -----------------------------------
     Segment/type of controller         2022 Updated      November 2021
                                          analysis          analysis
------------------------------------------------------------------------
Production:
    Low bleed.......................               6.8               2.6
    High bleed......................              21.2              16.4
    Intermittent vent...............               8.8               9.2
Transmission and Storage:
    Low bleed.......................               6.8              1.37
    High bleed......................              32.4              18.2
    Intermittent vent...............               2.3              2.35
------------------------------------------------------------------------

    As can be seen in Table 22, the emissions factors for low-bleed and 
high-bleed increased from those used for the November 2021 analysis, 
while the intermittent vent factors decreased slightly.
    One commenter indicated that while they appreciated that the EPA 
utilized emission factors from the API's Field Measurement Study, they 
believed that the use of the average intermittent pneumatic device vent 
rate was incorrect in this application.\134\ They stated that under 
this proposal, any intermittent device would be monitored routinely and 
repaired or replaced if malfunctioning, so the more appropriate 
emission factor is 0.28 scf whole gas/controller-hour, not the average 
emission factor of 9.2 scf whole gas/controller-hour that the EPA used 
in the November 2021 proposal. The commenter noted that the average 
emission factor should only be used for controllers that are not 
routinely monitored as part of a proactive monitoring and repair 
program or where the monitoring status is unknown. The commenter stated 
that the normal operation emission factor should be applied to 
controllers that are found to be operating normally as part of a 
proactive monitoring and repair program and contended that this 
approach achieves a nearly similar level of emission reduction for much 
less investment by operators.
---------------------------------------------------------------------------

    \134\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.
---------------------------------------------------------------------------

    The EPA agrees with the commenter that the lower emission factor is 
appropriate to represent the emissions level for intermittent vent 
controllers that are routinely monitored as part of a proactive 
monitoring and repair program. While the EPA recognizes that some 
companies have voluntarily implemented such programs, we do not have 
information to suggest that the majority of the intermittent vent 
controllers in operation are part of such a program. The average 
emission factor that the EPA used considers those low-emitting properly 
operating controllers, as well as those that are not operating

[[Page 74761]]

properly and that are venting during idle. The EPA finds that this 
average factor is the correct factor to represent the ``uncontrolled'' 
emissions from the universe of intermittent vent controllers.
    One commenter noted that all three sizes of model plants (small, 
medium, large) contained one high-bleed natural gas-driven controller. 
The commenter indicated that some state regulations do not allow for 
the use of high-bleed controllers and concluded that the EPA's baseline 
emissions analysis was likely skewed high.\135\
---------------------------------------------------------------------------

    \135\ See Document ID No. EPA-HQ-OAR-2021-0317-0749.
---------------------------------------------------------------------------

    The EPA agrees with this commenter. In addition to state 
regulations that do not allow the use of high-bleed controllers, in the 
absence of NSPS OOOOb, NSPS OOOOa would not allow the installation of 
high-bleed controllers at new sites. Therefore, in the updated analysis 
for new sources, the EPA did not include any high-bleed controllers in 
any of the model plants. Table 23 provides a summary of the pneumatic 
controller model plants and emissions. The emissions shown consider the 
changes in the emission factors provided above in Table 22.

                                         Table 23--Summary of Pneumatic Controller Model Plants for New Sources
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                            November 2021 analysis                                 2022 updated analysis
                                           -------------------------------------------------------------------------------------------------------------
            Segment/model plant                  Number of controllers         Emissions  (tpy)         Number of controllers         Emissions  (tpy)
                                           -------------------------------------------------------------------------------------------------------------
                                              HB \a\     LB \a\    INT \a\      CH4        VOC       HB \a\     LB \a\    INT \a\      CH4        VOC
--------------------------------------------------------------------------------------------------------------------------------------------------------
Production:
    Small.................................          1          1          2        5.7        1.6          0          2          2        4.7        1.3
    Medium................................          1          1          6       11.2        3.1          0          2          6       10.0        2.8
    High..................................          1          4         15       24.9        6.9          0          5         15       25.1        7.0
Trans/Storage:
    Small.................................          1          1          2        4.1        0.1          0          2          2        3.1       0.09
    Medium................................          1          1          6        5.7        0.2          0          2          6        4.6        0.1
    High..................................          1          4         15       10.0        0.3          0          5         15       11.6        0.3
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ HB--continuous high bleed, LB--continuous low bleed, INT--intermittent vent.

    Some commenters also disagreed with the costs used for the BSER 
analysis. One commenter said that the EPA's cost estimates were taken 
directly from the 2016 White Paper \136\ and that the EPA did not 
update the cost numbers for zero-emission electronic controllers, solar 
panels, or batteries.\137\ The EPA notes that the primary basis for the 
costs used for the November 2021 analysis was not the White Paper, but 
rather a 2016 report by Carbon Limits, a consulting company with 
longstanding experience in supporting efficiency measures in the 
petroleum industry.\138\ One commenter \139\ pointed out that Carbon 
Limits updated their report in early 2022,\140\ and recommended that 
the EPA utilize the more recent information in that report since it 
included more up-to-date research on zero emissions options for 
pneumatic controllers. We reviewed the updated 2022 Carbon Limits 
report and we agree with the commenter that the information presented 
is well researched and representative of the costs of zero-emission 
pneumatic controller technologies.
---------------------------------------------------------------------------

    \136\ U.S. EPA OAQPS. Oil and Natural Gas Sector Pneumatic 
Devices. Report for Oil and Natural Gas Sector Pneumatic Devices 
Review Panel. April 2014.
    \137\ See Document ID No. EPA-HQ-OAR-2021-0317-0924.
    \138\ Carbon Limits. (2016) Zero emission technologies for 
pneumatic controllers in the USA--Applicability and cost 
effectiveness.
    \139\ See Document ID No. EPA-HQ-OAR-2021-0317-0844.
    \140\ Carbon Limits. (2022) Zero emission technologies for 
pneumatic controllers in the USA Updated applicability and cost 
effectiveness. Available at https://cdn.catf.us/wp-content/uploads/2022/01/31114844/Zero-Emissions-Technologoes-for-Pneumatic-Controllers-2022.pdf.
---------------------------------------------------------------------------

    In addition to updating the analysis to reflect the information in 
the 2022 Carbon Limits report, we also increased the estimate of 
installation costs and considered operation and maintenance costs for 
all types of pneumatic controller systems not driven by natural gas.
    One commenter mentioned that for zero emission, electrical 
controller setups, skilled electrical labor is required for wiring, 
programming, and tuning, which cannot be conducted by lease operators 
that would otherwise manage this equipment. According to the commenter, 
one available estimate is as high as $20,000 in labor costs per multi-
well pad.\141\ In the November 2021 BSER analysis, we assumed that the 
installation and engineering costs were 20 percent of the total cost of 
the equipment. For the updated analysis, we increased those costs to 50 
percent. The results were installation and engineering costs ranging 
from $8,500 for a small electrical controller system to almost $52,000 
for a large instrument air system.
---------------------------------------------------------------------------

    \141\ See Document ID No. EPA-HQ-OAR-2021-0317-0749.
---------------------------------------------------------------------------

    Another change to the capital cost estimate that the EPA made was 
to adjust the capital cost to represent the difference in the capital 
cost between the pneumatic controller system not driven by natural gas 
and the natural gas-driven controllers that would be used in the 
absence of a zero emissions requirement. These costs, which were 
calculated based on $2,227 equipment costs and the $387 installation 
cost per pneumatic controller, were subtracted from the total capital 
investment of the pneumatic controller systems not driven by natural 
gas.
    For the November 2021 analysis, the annual costs were estimated as 
the capital recovery of the original capital investment. This assumed 
that the operating and maintenance costs for a pneumatic controller 
system not driven by natural gas was the same as for natural gas-driven 
controllers. For this analysis, we took into account differences in 
operating costs. In general, the operating and maintenance costs for 
pneumatic controller systems not driven by natural gas is less than 
that of natural gas driven controllers, particularly if the gas is wet 
gas. To estimate the operating costs for natural gas-driven 
controllers, we used the average between the wet gas and dry gas cost 
from the 2022 Carbon Limits report. This resulted in a net savings in 
the annual operations and maintenance costs for electric and solar-
powered controller systems. There are additional operating and 
maintenance costs

[[Page 74762]]

associated with instrument air systems, which resulted in an overall 
increase in these costs as compared to natural gas-driven controllers.
    The costs for electric controllers and instrument air systems 
assume access to electrical power (that is, access to the grid). Solar-
powered controllers can be utilized at remote sites that do not have 
access to electrical power. Instrument air systems can also be utilized 
at sites without access to the electricity grid, but these would 
require the installation and operation of a generator. These generators 
could be powered by engines fueled by natural gas, diesel, or by solar 
energy. One commenter provided estimated costs ranging from $60,000 to 
over $200,000 for an instrument air system driven by a natural gas 
generator.\142\ Using the information provided by the commenter, the 
EPA estimated costs for the three model plants. Note that the largest 
model plant contained 20 controllers and the highest cost provided by 
the commenter was for a site with more than 200 controllers. Therefore, 
this cost was not utilized. The EPA is specifically requesting more 
detailed information on the use of generators at sites without access 
to the grid to power pneumatic controllers, primarily to power 
instrument air systems. The EPA is also interested in receiving more 
information on the costs associated with this equipment. Table 24 
provides the updated pneumatic controller systems not driven by natural 
gas costs. This table also provides the costs from the November 2021 
analysis for comparison.
---------------------------------------------------------------------------

    \142\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.

                           Table 24--Total Capital and Annual Costs for Pneumatic Controller Systems Not Driven by Natural Gas
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                   November 2021 analysis                                  2022 Updated analysis
                                          --------------------------------------------------------------------------------------------------------------
               Model plant                                                                                                        Adjusted
                                                         TCI \a\                             TAC \b\                 TCI \a\      TCI \b\      TAC \c\
--------------------------------------------------------------------------------------------------------------------------------------------------------
Electric:
    Small System.........................  $25,494...........................  $2,799............................      $25,742      $15,287         $762
    Medium System........................  45,889............................  5,038.............................       46,335       25,426          959
Solar:
    Small System.........................  28,171............................  3,093.............................       27,286       16,831        1,112
    Medium System........................  51,242............................  5,626.............................       49,424       28,515        1,679
Instrument Air System--Grid:
    Small System.........................  not estimated.....................  not estimated.....................       57,966       47,512        9,285
    Medium System........................  not estimated.....................  not estimated.....................       92,335       71,426       10,658
    Large System.........................  95,602............................  10,497............................      165,550      113,277       14,891
Instrument Air System--Natural Gas
 Generator:
    Small System.........................  not estimated.....................  not estimated.....................      105,570       95,115       12,604
    Medium System........................  not estimated.....................  not estimated.....................      121,240      100,231       11,914
    Large System.........................  not estimated.....................  not estimated.....................      242,850      190,577       19,565
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ TCI = Total capital investment includes capital cost of equipment plus engineering and installation costs.
\b\ Adjusted TCI = Total capital investment minus the cost that would have been incurred if natural gas-driven controllers had been installed.
\c\ TAC = Total annual costs including capital recovery (at 7 percent interest and 15-year equipment life) and operation and maintenance costs.

    The controllers not driven by natural gas do not emit methane or 
VOC. Therefore, the emission reductions associated with these systems 
equal the total emissions shown above in Table 23. The estimated cost 
effectiveness values for the controllers not driven by natural gas are 
provided in Table 25. In addition to the cost effectiveness values, 
Table 25 provides a conclusion regarding whether the estimated cost 
effectiveness value is within the range that the EPA has typically 
considered to be reasonable. The ``overall'' reasonableness 
determination is classified as ``Y'' if the cost effectiveness of 
either methane or VOC is within the range that the EPA considers 
reasonable for that pollutant, or ``N'' if both the methane and VOC 
cost effectiveness values are beyond the range the EPA considers 
reasonable on a multipollutant basis.

 Table 25--Summary of Pneumatic Controller Systems Not Driven by Natural Gas Cost Effectiveness for New Sources
----------------------------------------------------------------------------------------------------------------
                                                   Cost effectiveness ($/ton) \a\--reasonable?
                                --------------------------------------------------------------------------------
      Segment/model plant               Single pollutant                 Multipollutant
                                ----------------------------------------------------------------   Overall \a\
                                     Methane           VOC           Methane           VOC
----------------------------------------------------------------------------------------------------------------
Production:
    Small--Electric                      $162-Y          $581-Y           $81-Y          $291-Y               Y
     controllers--grid.........
    Small--Electric                       238-Y           856-Y           119-Y           428-Y               Y
     controllers--solar........
    Small--Compressed air--grid         1,969-Y         7,082-N           984-Y         3,541-Y               Y
    Small--Compressed air--             2,673-N         9,615-N         1,336-Y         4,807-Y               Y
     generator.................
    Medium--Electric                       96-Y           344-Y            48-Y           172-Y               Y
     controllers--grid.........
    Medium--Electric                      167-Y           602-Y            84-Y           301-Y               Y
     controllers--solar........
    Medium--Compressed air--            1,062-Y         3,820-Y           531-Y         1,910-Y               Y
     grid......................
    Medium--Compressed air--            1,187-Y         4,270-Y           594-Y         2,135-Y               Y
     generator.................
    Large--Electric                        62-Y           222-Y            31-Y           111-Y               Y
     controllers--grid.........
    Large--Electric                       130-Y           467-Y            65-Y           234-Y               Y
     controllers--solar........

[[Page 74763]]

 
    Large--Compressed air--grid           593-Y         2,135-Y           297-Y         1,067-Y               Y
    Large--Compressed air--               780-Y         2,805-Y           390-Y         1,402-Y               Y
     generator.................
Transmission and Storage:
    Small--Electric                       247-Y         8,942-N           124-Y         4,471-Y               Y
     controllers--grid.........
    Small--Electric                       364-Y        13,164-N           182-Y         6,582-N               Y
     controllers--solar........
    Small--Compressed air--grid         3,015-N       108,939-N         1,507-Y        54,469-N               N
    Small--Compressed air--             4,093-N       147,891-N         2,046-N        73,946-N               N
     generator.................
    Medium--Electric                      207-Y         7,474-N           103-Y         3,737-Y               Y
     controllers--grid.........
    Medium--Electric                      362-Y        13,082-N           181-Y         6,541-N               Y
     controllers--solar........
    Medium--Compressed air--            2,299-N        83,066-N         1,149-Y        41,533-N               N
     grid......................
    Medium--Compressed air--            2,570-N        92,854-N         1,285-Y        46,427-N               N
     generator.................
    Large--Electric                       134-Y         4,830-Y            67-Y         2,415-Y               Y
     controllers--grid.........
    Large--Electric                       281-Y        10,156-N           141-Y         5,078-Y               Y
     controllers--solar........
    Large--Compressed air--grid         1,285-Y        46,422-N           642-Y        23,211-N               Y
    Large--Compressed air--             1,688-Y        60,992-N           844-Y        30,496-N               Y
     generator.................
----------------------------------------------------------------------------------------------------------------
\a\ For the production and processing segments, the owners and operators realize the savings for the natural gas
  that not emitted and lost. The cost effectiveness values shown do not consider these savings. Note that the
  consideration of savings does not impact whether the cost effectiveness of any of these options falls within
  the ranges considered reasonable by the EPA.
\b\ For overall cost effectiveness to be considered reasonable, either the cost effectiveness of methane or VOC
  on a single pollutant basis must be within the ranges considered reasonable by the EPA, or the cost
  effectiveness of both methane and VOC on a multipollutant basis must be within the ranges considered
  reasonable by the EPA.

iii. Proposed BSER Conclusion.
    As demonstrated in the analysis and shown in Table 25, there are 
pneumatic controller options for controllers not driven by natural gas 
at sites in the production and transmission and storage segments where 
the cost effectiveness is within the ranges considered to be reasonable 
by the EPA. These options can be utilized at sites with access to grid 
electricity and remote sites that do not have this access. This 
conclusion is consistent with the findings in the November 2021 
proposal.
    In addition to these options that use pneumatic controllers not 
driven by natural gas, there are two types of natural gas-driven 
controllers that we are proposing as zero-emissions options: (1) 
Controllers whose emissions are collected and routed to a process, and 
(2) self-contained natural gas pneumatic controllers. As noted in 
section IV.D.1.b.i, these natural-gas driven controllers are included 
in the revised proposed definition of affected facility, meaning that 
they would be subject to standards to ensure that they are operated and 
maintained in a manner that ensures zero emissions of methane and VOC. 
We are including these as compliance options in this proposed action 
because: (1) they are included as compliance options under several 
state rules, and (2) there is cursory information indicating that they 
are utilized in some locations. However, the available information 
about the prevalence of either of these options at sites in the oil and 
natural gas production or transmission and storage segments is very 
limited. Therefore, the EPA is requesting is requesting comment on 
several issues related to these controllers.
    The EPA is interested in several aspects related to the option of 
collecting the pneumatic controller emissions and routing them to a 
process. First, we are soliciting information that describes specific 
situations where owners and operators have utilized this option to use, 
rather than lose, the valuable natural gas emitted from pneumatic 
controllers. We are interested in the specific processes and equipment 
needed, as well as their costs.
    Second, our understanding is that routing emissions from pneumatic 
controllers to a process achieves a 100 percent reduction in emissions. 
This understanding is based on the fact that the natural gas that is 
emitted from pneumatic controllers is drawn directly from the raw 
product gas stream that will be collected and routed to a gathering and 
boosting station and eventually to a natural gas processing plant 
(i.e., the gas ``sales line''). Therefore, the emissions from pneumatic 
controllers are of the same composition as the gas in the sales line. 
Since the emissions are at atmospheric pressure, it is likely that the 
gas would need to be compressed prior to re-introduction to the sales 
line. We do not expect that this compression would result in emissions. 
Similarly, since the gas composition of these emissions is typically 
high in methane, the heat content would make it amendable to being used 
as fuel, or introduced with the primary fuel stream for use in an 
engine without the need for additional processing that could result in 
emissions. We are interested in information to support this 
understanding that routing emissions from pneumatic controllers to a 
process achieves a 100 percent reduction in emissions.
    The 100 percent emissions reductions that we believe can be 
achieved for controllers contrasts with routing emissions from storage 
vessels or centrifugal compressor wet seal fluid degassing systems to a 
process where the emissions are of a different composition from the 
sales gas. For these situations, a VRU or other treatment is necessary 
to obtain a gas stream whose composition is suitable to be returned to 
the sales line or used for another purpose. A VRU often includes a 
scrubber, separator, condenser, or other component that has a small 
vent stream emitted to the atmosphere. In addition, the complex nature 
of VRUs results in the need for maintenance or other situations where 
the VRU may be bypassed, and emissions vented for short periods of 
time. Because of both of these situations, the EPA has historically 
assumed that VRUs achieve

[[Page 74764]]

a 95 percent reduction or greater in emissions.
    The EPA requests information on the assumption that installation of 
VRUs would not be needed to enable the use of emissions from pneumatic 
controllers in a process. If there are situations where a VRU is 
needed, the EPA is interested in the conditions that result in this 
need, as well as the emissions reduction achieved and the costs.
    We are aware of technical limitations of self-contained 
controllers, namely that their applicability is limited by a number of 
conditions (e.g., pressure differential, downstream pressure, etc.). 
The EPA is therefore specifically soliciting information on the 
frequency of the use of these self-contained controllers in the field, 
as well as confirmation of specific limitations and costs. We are also 
interested in information to support our understanding that self-
contained controllers achieve 100 percent reduction in emissions when 
maintained and operated properly.
    Several commenters maintain that there are technical limitations 
that will not allow pneumatic controllers not driven by natural gas to 
be utilized at sites without electricity, particularly solar-powered 
controllers.\143\ One commenter stated that while the EPA suggested the 
use of onsite solar generation paired with battery storage as an 
alternative to grid electricity, such systems are currently ``uncommon, 
unreliable, and will likely increase the frequency of facility upsets, 
which will increase safety risks such as overpressure events and 
spills.'' \144\ Another commenter stated that while there may be some 
pilot projects within the industry, it has not been demonstrated that 
reliable turnkey packages are available on a widescale basis.\145\ 
Several commenters noted that there are severe geographic limitations 
to the use of any solar-powered devices. One noted that West Virginia 
averages only 164 days of sunshine per year, compared with an average 
of 205 days for the rest of the United States. Even in typically sunny 
states, operations in canyons or mountain valleys receive significantly 
limited sunlight exposure. Snow and ice raise additional reliability 
concerns during winter months.\146\ Another commenter stated that 
large-scale solar applications have not yet been tested in winter 
months when there is more cloud coverage, increased snow cover, and 
less sunlight in more northern locations (e.g., Colorado, North Dakota, 
Idaho, and Wyoming).\147\ One industry organization agreed that solar 
power might be an option but reported that their member companies have 
not yet been able to demonstrate this to be universally true in Utah's 
Uinta Basin. This organization cited specific problems such as the 
requirement of excess generation and battery storage capacity to 
maintain operations during wintertime inversions and challenges from 
snowstorms, which could cover the solar panels and inhibit or prevent 
electricity generation. They conclude that utilizing solar electricity 
for oil and gas operations in Utah may be labor intensive, costly, and 
unreliable such that operations would still require backup power from 
the electric grid or from generators.\148\ Another commenter also 
mentioned that it is probable that supplemental power via natural gas 
or diesel-powered generators could be required during winter months 
and/or severe weather events, which would be necessary to ensure a 
continuous power supply, and, thus, a controlled operation. This 
commenter also noted that interruptions within the control system pose 
safety risks to operators and can damage processing equipment, which 
could potentially lead to excess emissions associated with equipment 
malfunctions.\149\
---------------------------------------------------------------------------

    \143\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0817, EPA-HQ-
OAR-2021-0317-0743, EPA-HQ-OAR-2021-0317-0749, and EPA-HQ-OAR-2021-
0317-0808.
    \144\ See Document ID No. EPA-HQ-OAR-2021-0317-0793.
    \145\ See Document ID No. EPA-HQ-OAR-2021-0317-0599.
    \146\ See Document ID No. EPA-HQ-OAR-2021-0317-0817.
    \147\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.
    \148\ See Document ID No. EPA-HQ-OAR-2021-0317-0740.
    \149\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.
---------------------------------------------------------------------------

    One commenter indicated that they were unaware of any operators 
converting to solar-powered electric controllers at this time. They 
said while the technology seems promising, many of these solar systems 
have not yet been proven reliable for all remote locations or facility 
designs and are not ready for deployment across the country at the 
large scale that the EPA's proposed rules would require. They note that 
in 2014, the EPA stated ``solar-powered controllers can replace 
continuous bleed controllers in certain applications but are not 
broadly applicable to all segments of the oil and natural gas 
industry.'' \150\
---------------------------------------------------------------------------

    \150\ Oil and Natural Gas Sector Pneumatic Devices, Review 
Panel, USEPA, OAQPS, 2014: https://www.ourenergypolicy.org/wp-content/uploads/2014/04/epa-devices.pdf.
---------------------------------------------------------------------------

    However, other commenters disagreed and supported the EPA's 
November 2021 proposal to require zero-emission controllers. Commenters 
cited several state rules that require all new pneumatic controllers to 
be non-emitting, including states with colder climates (Colorado). As 
the EPA also indicated in the November 2021 proposal, there are 
Canadian provinces that have successfully implemented non-emitting 
controller regulations. Comments were also provided by vendors that 
report the successful installation and operation of zero-emission 
controller systems in a variety of climate conditions.\151\ One of 
these vendors notes the installation of solar-driven instrument air 
systems in several states, including Wyoming and Colorado.\152\
---------------------------------------------------------------------------

    \151\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0838 and EPA-HQ-
OAR-2021-0317-0802.
    \152\ See Document ID No. EPA-HQ-OAR-2021-0317-0838.
---------------------------------------------------------------------------

    In a supplement to their 2022 report that was provided in a late 
comment, Carbon Limits addressed many of the alleged shortcomings of 
solar and other zero-emitting controller technologies raised in public 
comments. They state, ``[a]ddressing the queries on the reliability of 
solar systems for remote locations and cold states, the technology 
providers and operators interviewed as part of this assessment have 
solar-powered controllers installed at well sites in remote and cold 
locations such as Northern Alberta and British Colombia, without major 
reliability issues. Some of the interviewed technology providers have 
installed these systems in over 400 well-sites in these states and 
provinces. The commenter further refers to a statement by the EPA from 
2014. However, it is to be noted that solar technology has improved 
drastically from 2014 to 2021. Efficiency has increased while costs 
have gone down significantly. Solar-powered controllers are capable of 
operating at low temperatures and remote locations, among different gas 
sectors. When it comes to snow cover on panels affecting the 
performance of solar cells, all the interviewees stated that the panels 
are placed at a low angle, to catch ample sun in the winter months. 
Most often, these panels are placed vertically, eliminating snow cover 
on the solar panels.'' \153\ Commenters also indicated that at sites 
without electricity, owners or operators could install a generator to 
power an instrument air system.
---------------------------------------------------------------------------

    \153\ See Document ID No. EPA-HQ-OAR-2021-0317-1451.
---------------------------------------------------------------------------

    Under CAA section 111(b), EPA must show that a BSER determination 
has been ``adequately demonstrated.'' The EPA concludes that zero-
emission

[[Page 74765]]

pneumatic controller systems that do not use natural gas meet this 
standard at sites both with and without access to electricity. In 
addition, as discussed above, we have concluded that there are options 
available at sites in all segments of the industry that have cost-
effective values considered reasonable by the EPA.
    Secondary impacts from these non-natural gas-driven, zero-emission 
controllers, particularly from the use of instrument air systems are 
indirect, variable, and dependent on the electrical supply used to 
power the compressor. The 2016 Carbon Limits report indicates that a 
small instrument air compressor would require around 5 horsepower (HP) 
of air compression capacity, while a larger facility would require up 
to 20 HP. Assuming the compressor operates one-half of the total hours 
in a year, and using an electricity factor of 0.75 HP/kilowatt, the 
compressor yields an annual electricity usage of around 100 mmBtu/yr 
for a 5 HP compressor and 400 mmBty/yr for a 20 HP compressor. There 
would be secondary air pollution impacts associated with the generation 
of this electricity. The secondary criteria pollutant emissions are 
estimated to be 7 lbs/yr CO, 60 lbs/yr NO2, 3 lbs/yr PM, 1 
lb/yr PM2.5, and 120 lbs/yr SO2 for a 5 HP 
compressor and 29 lbs/yr CO, 239 lbs/yr NO2, 12 lbs/yr PM, 4 
lb/yr PM2.5, and 478 lbs/yr SO2 for a 20 HP 
compressor. The secondary GHG emissions generated as a result of this 
electricity generation are 20,489 lbs/yr CO2, 2 lbs/yr 
methane, and 1lb/yr N2O for a 5 HP compressor and 81,955 
lbs/yr CO2, 10 lbs/yr methane, and 2 lbs/yr N2O 
for a 20 HP compressor. Considering the global warming potential of 
these GHGs, the total CO2e emissions would be 20,667 lbs 
CO2e from a 5 HP compressor and 82,669 lbs CO2e 
from a 20 HP compressor. These total CO2e would represent a 
more than 90 percent reduction in the CO2e emissions when 
compared to the uncontrolled methane emissions from natural gas driven 
controllers. No other secondary impacts are expected.
    Commenters indicated that at sites without electricity, owners or 
operators would likely install a generator to power an instrument air 
system. These commenters contended that relying on a generator would 
result in emissions of criteria pollutants and carbon monoxide (CO) 
that could potentially offset the emissions reductions from the methane 
and VOC. One commenter provided an estimate that a natural gas-fired 
generator of approximately 200 horsepower would be needed to support 
reliable operation of a large instrument air system without grid power. 
This commenter estimated emissions from a generator that size to be 
1.94 tpy NOX, 3.88 tpy of CO, 1.36 tpy of VOC, 0.12 tpy of 
particulate matter with a diameter of 10 micrometers or less 
(PM10), 0.14 tpy CH4 and 730 tpy of 
CO2.\154\
---------------------------------------------------------------------------

    \154\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.
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    The EPA recognizes that if owners and operators elect to comply by 
installing and operating a generator, there will be secondary emissions 
generated from the fuel combustion. However, we also point out that, 
for a site with 100 controllers (a size cited by the commenter 
requiring a large instrument air system), these secondary emissions 
would represent approximately a 77 percent decrease in CO2 
equivalent emissions and a 96 percent decrease in VOC emissions from a 
site with 25 low bleed and 75 intermittent bleed controllers.
    In light of the above, we find that the BSER for reducing methane 
and VOC emissions from natural gas-driven controllers in the production 
and transmission and storage segments of the industry to be the use of 
controllers that have a methane and VOC 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 that 
each pneumatic controller affected facility be designed and operated 
with a methane and VOC emission rate of zero in the production and 
transmission and storage segments of the source category, with the 
following exception for sites in Alaska that do not have access to grid 
electricity.
    In the November 2021 proposal, we determined a separate BSER for 
the subset of pneumatic controllers, specifically those at sites in 
Alaska that do not have access to electricity. We also proposed 
specific requirements for these controllers. We are not proposing any 
changes to these requirements in this supplemental proposal. 
Specifically, these sites would be required to use low-bleed 
controllers (instead of high-bleed controllers) and would be allowed to 
use high-bleed controllers instead of low-bleed based only upon a 
showing of functional needs. In addition, we proposed that owners or 
operators at such sites be required to inspect intermittent vent 
controllers to ensure they are not venting during idle periods. The 
rationale for this decision was discussed in the November 2021 proposal 
(86 FR 63207; November 15, 2021).
    The EPA notes that the BSER determination for pneumatic controllers 
at natural gas processing plants was also not revisited in this 
supplemental proposal. Therefore, the November 2021 BSER determination 
of zero emission controllers at natural gas processing plants is 
retained in this supplemental proposal. The rationale for this decision 
is contained in the November 2021 proposal (86 FR 63207- 63208; 
November 15, 2021).
iv. Routing to an Existing Control Device
    Several commenters requested that the EPA include an option to 
collect the emissions from natural gas-driven controllers and route 
them to a flare or combustion device that achieves 95 percent reduction 
in methane and VOC. These comments stated that in many situations, an 
onsite control device already exists and that using it would be a cost-
effective method of achieving significant emission reductions.
    The EPA acknowledges that this is a viable option to achieve 
emission reductions from natural gas-driven pneumatic controllers. 
However, as discussed above, we have determined that BSER for pneumatic 
controllers is use of one of the several types of controllers that have 
zero methane and VOC emissions. Thus, routing to an existing control 
device (i.e., achieving 95 percent reduction) would result in a less 
stringent standard than the BSER. In the 2021 Inventory of U.S. 
Greenhouse Gas Emissions and Sinks (GHGI), the estimated methane 
emissions for 2019 from pneumatic controllers were 700,000 metric tons 
of methane for petroleum systems and 1.4 million metric tons for 
natural gas systems. These levels represent 45 percent of the total 
methane emissions estimated from all petroleum systems (i.e., 
exploration through refining) sources and 22 percent of all methane 
emissions from natural gas systems (i.e., exploration through 
distribution). While we recognize that these emissions include 
emissions from existing sources, it is clear that pneumatic controllers 
represent a significant source of methane and VOC emissions. Allowing 
an option that results in 5 percent more emissions would be a quite 
significant increase.
    The EPA recognizes that there are other instances in the proposed 
rule where there are options allowed that are less stringent than the 
measures determined to be BSER. However, in each of these situations, 
the EPA is convinced that there are genuine technical limitations or 
safety issues that make compliance with the BSER infeasible. For 
pneumatic controllers, the EPA maintains that there is a

[[Page 74766]]

technically feasible option available for all production, processing, 
and transmission and storage sites, except for sites in Alaska without 
access to electricity. Therefore, the proposed NSPS OOOOb does not 
include any alternative non-zero emission standards for pneumatic 
controllers. The EPA is interested in information that may dispute the 
conclusion that there is a technically feasible option that does not 
emit methane or VOC available for all sites in all segments. Some 
commenters raised concerns about specific situations that may make 
individual technologies impracticable to implement (e.g., the inability 
of solar-powered controller systems to meet the needs at certain remote 
locations that do not have access to electricity). Although the EPA 
will consider any additional information commenters may submit about 
such situations, the EPA notes that there are multiple options for 
meeting the proposed zero-emission standard and that limitations on the 
use of one technology at any given site does not mean that other 
options for meeting the standard are unavailable. As a result, the EPA 
is particularly interested in understanding whether there are site 
characteristics that would make every zero-emitting option (electric 
controllers powered by the grid or by solar power; instrument air 
systems powered by the grid, a generator, or by solar power; collecting 
the emissions and routing them to a process; self-contained 
controllers, etc.) technically infeasible at the site.
c. Summary of Proposed Standards
    In this supplemental proposal, the pneumatic controller affected 
facility is defined as the collection of natural gas-driven pneumatic 
controllers at a well site, centralized production facility, onshore 
natural gas processing plant, or a compressor station. This definition 
applies in all segments of the oil and natural gas source category. 
Natural gas-driven pneumatic controllers that function as emergency 
shutdown devices and pneumatic controllers that are not driven by 
natural gas are exempt from the affected facility, provided that the 
records are maintained to document these conditions. In addition to the 
modification definition in 40 CFR 60.14 and the reconstruction 
definition in 40 CFR 60.15, the proposed rule includes clarification of 
these terms for the pneumatic controller affected facility. A 
modification occurs when the number of natural gas-driven pneumatic 
controllers at a site is increased by one or more, and reconstruction 
occurs when either the cost of the controllers being replaced exceeds 
50 percent of the cost to replace all the controllers, or when 50 
percent or more of the pneumatic controllers at a site are replaced.
    The proposed standard for pneumatic controller affected facilities 
is zero emissions of methane and VOC to the atmosphere. An exception to 
this standard exists for pneumatic controller affected facilities 
located at sites in Alaska without access to electrical power. The 
proposed rule does not specify how this emission rate of zero must be 
achieved, but a variety of viable options are available. All 
controllers at a site that are not driven by natural gas (e.g., 
pneumatic controllers driven by compressed air, electric controllers, 
solar-powered controllers) are not part of the pneumatic controller 
affected facility, provided that documentation is maintained as 
previously discussed. If all pneumatic controllers at a site are not 
natural gas-driven, then there would be no pneumatic controller 
affected facility at the site, provided the documentation is 
maintained.
    Natural gas-driven controllers can comply with the zero emissions 
standard by collecting and routing emissions via a CVS to process, or 
by using self-contained controllers. The proposed rule defines a self-
contained pneumatic controller as a natural gas-driven pneumatic 
controller that releases gas into the downstream piping and not to the 
atmosphere, resulting in zero methane and VOC emissions.
    If you comply by routing the emissions to a process, the CVS that 
collects the emissions must be routed to a process through a CVS that 
meets the requirements in proposed 40 CFR 60.5411b, paragraphs (a) and 
(c). These requirements include certification by a professional or in-
house engineer that the CVS was designed properly, and that the CVS is 
operated with no identifiable emissions as demonstrated through initial 
and periodic inspections, observations, and measurements. This includes 
monitoring using OGI at the same frequency as required under the 
fugitive monitoring program. All issues identified must be corrected. 
Required records would include the certification and records of all 
inspections and any corrective actions to repair the defect or the 
leak.
    If you comply by using a self-contained natural gas-driven 
pneumatic controller, the controller must be designed and operated with 
no detectable emissions, as demonstrated by conducting initial and 
quarterly inspections using optical gas imaging. Required records would 
include records of all inspections and any corrective actions to repair 
the defect or the leak.
    The proposed rule includes an exemption from the zero-emission 
requirement for pneumatic controllers in Alaska at locations where 
electrical power is not available. In these situations, the proposed 
standards require the use of a low-bleed controller (i.e., a controller 
with a natural gas bleed rate less than or equal to 6 scfh). Records 
would be required to demonstrate that the controller is designed and 
operated to achieve a bleed rate less than or equal to 6 scfh. For 
controllers in Alaska at location without electrical power, the 
proposed rule includes the exemption that would allow the use of high-
bleed controllers instead of low-bleed based on functional needs 
(including but not limited to response time, safety, or positive 
actuation). To utilize this exemption, a demonstration of the 
functional need must be made and submitted in the initial annual 
report. The proposed rule also includes requirements for natural gas-
driven intermittent vent controllers at these sites in Alaska without 
access to electrical power. Specifically, the proposed rule would 
require that an intermittent vent not vent to the atmosphere during 
idle periods. Compliance with this requirement would be demonstrated by 
modifying the fugitive emissions monitoring plan to include these 
intermittent vents, monitoring them at the schedule required by the 
site for the fugitive emissions components affected facility, and 
repairing any leaks or defects identified. Records would be required of 
all inspections and repairs.
2. EG OOOOc
    The November 2021 proposal defined the pneumatic controller 
designated facility for EG OOOOc as each natural gas-driven controller. 
As with the change discussed above for the NSPS OOOOb affected 
facility, we are also proposing that the EG OOOOc designated facility 
definition to be the collection of natural gas-driven pneumatic 
controllers at a well site, centralized production facility, onshore 
natural gas processing plant, or a compressor station. This definition 
applies in all segments of the oil and natural gas source category.
    In response to comments received and additional information 
collected, we also updated the BSER analysis for existing sources. The 
same basic changes were made to the existing source analysis as 
discussed above for the new source analysis. However, there were a few 
instances where the emissions and costs differed for existing sources 
as compared to new. These are discussed in the following sections.

[[Page 74767]]

a. Model Plant Emissions
    As noted above, for the new source analysis we adjusted the model 
facilities to remove all high-bleed controllers since NSPS OOOOa and 
many state rules already prohibit the use of high-bleed controllers. 
While there are limited instances where states impose this requirement 
on existing sources, we concluded that the best representation for 
pneumatic controller model plants was to include one high-bleed for 
each type of facility. The emissions, calculated using the updated 
emission factors provided in Table 22, are provided below in Table 26.

                  Table 26--Summary for Pneumatic Controller Model Plants for Existing Sources
----------------------------------------------------------------------------------------------------------------
                                                               Number of controllers
                                                 ------------------------------------------------     Methane
               Segment/model plant                                                 Intermittent      emissions
                                                    High bleed       Low bleed         vent            (tpy)
----------------------------------------------------------------------------------------------------------------
Production:
    Small.......................................               1               1               2             6.9
    Medium......................................               1               1               6            12.2
    High........................................               1               4              15            27.3
Transmission and Storage:
    Small.......................................               1               1               2             7.4
    Medium......................................               1               1               6             9.0
    High........................................               1               4              15            15.9
----------------------------------------------------------------------------------------------------------------

b. Costs for Controllers Not Driven by Natural Gas
    There were instances where the estimated costs for the systems for 
controllers not driven by natural gas were different for existing 
sources and for new sources. Following are brief descriptions of the 
reasons for these differences.
    For electric and solar-powered controllers, the new source capital 
costs included the cost for controller valves. For existing sources, we 
assumed that the existing valves could be used for converting from 
natural gas pneumatic controllers. For new sites, the cost of natural 
gas-driven controllers was subtracted from the cost of the controllers 
not driven by natural gas, as those capital expenses would be 
``saved.'' This adjustment was not made for existing sources. We 
assumed that the relative engineering and installation costs would be 
higher at an existing site; therefore, we assume an engineering and 
installation cost of 100 percent of the capital costs. For instrument 
air systems, the new site costs included costs for the new controllers, 
while the assumption was that existing sources could continue to use 
the existing controllers that were formerly driven by natural gas. The 
instrumentation cost for a retrofit for an existing site was assumed to 
be 40 percent higher than for a new site, and the engineering and 
installation costs were assumed to be 100 percent of the capital costs 
for existing sites (as opposed to 50 percent for new sites). As with 
electric and solar-powered controllers, the cost of the natural gas-
driven controllers not needed was not subtracted from the existing 
source capital costs.
    The operation and maintenance costs for existing sources used were 
the same as for new sources. Therefore, the only difference in total 
annual costs was due to the difference in the capital recovery costs 
because of the different total capital investment.
    Table 27 compares the total capital investment and total annual 
cost for new sources and existing sources for each model plant and zero 
emission controller technology.

Table 27--Comparison of Total Capital and Annual Costs for Non-Emitting Controllers Not Driven by Natural Gas at
                                            New and Existing Sources
----------------------------------------------------------------------------------------------------------------
                                                            New sources                  Existing sources
                                                 ---------------------------------------------------------------
                   Model plant                     Adjusted TCI
                                                      \a\ \b\         TAC \c\         TCI\a\        TAC\c\ \d\
----------------------------------------------------------------------------------------------------------------
Electric:
    Small System................................         $15,287            $762         $20,593          $1,345
    Medium System...............................          25,426           1,112          34,322           1,936
    Large System................................          55,842           1,550          75,508           3,709
Solar:
    Small System................................          16,831             959          22,653           1,761
    Medium System...............................          28,515           1,679          38,441           2,768
Large System....................................          63,049           3,258          85,119           5,681
Instrument Air System--Grid:
    Small System................................          47,512           9,285          58,636          10,506
    Medium System...............................          71,426          10,658          76,481          11,213
Large System....................................         113,277          14,891         127,469          16,449
Instrument Air System--Generator:
    Small System................................          95,115          12,604         120,000          15,337
    Medium System...............................         100,231          11,914         120,000          14,085
    Large System................................         190,577          19,565         220,000          22,795
----------------------------------------------------------------------------------------------------------------
\a\ TCI = Total capital investment includes capital cost of equipment plus engineering and installation costs.
\b\ Adjusted TCI = Total capital investment minus the cost that would have been incurred if natural gas-driven
  controllers had been installed.
\c\ TAC = Total annual costs including capital recovery (at 7 percent interest and 15-year equipment life) and
  operation and maintenance costs.
\d\ For the production segment, the owners and operators realize the savings for the natural gas that not
  emitted and lost. The cost values shown do not consider these savings.

[[Page 74768]]

c. Existing Source BSER Determination
    Table 28 shows the cost effectiveness values for methane of the 
controller technologies that are not driven by natural gas and that do 
not emit methane.

 Table 28--Summary of Pneumatic Controller Systems Not Driven by Natural
           Gas Methane Cost Effectiveness for Existing Sources
------------------------------------------------------------------------
                                             Cost
                                      effectiveness \a\
        Segment--model plant            ($/ton methane     Reasonable?
                                           reduced)
------------------------------------------------------------------------
Production Segment:
    Small--Electric controllers--                  $195               Y
     grid...........................
    Small--Electric controllers--                   255               Y
     solar..........................
    Small--Compressed air--grid.....              1,524               Y
    Small--Compressed air--generator              2,225               N
    Medium--Electric controllers -                  158               Y
     grid...........................
    Medium--Electric controllers--                  227               Y
     solar..........................
    Medium--Compressed air--grid....                918               Y
    Medium--Compressed air--                      1,153               Y
     generator......................
    Large--Electric controllers -                   136               Y
     grid...........................
    Large--Electric controllers--                   208               Y
     solar..........................
    Large--Compressed air--grid.....                603               Y
    Large--Compressed air--generator                836               Y
Transmission and Storage Segment:
    Small--Electric controllers--                   181               Y
     grid...........................
    Small--Electric controllers--                   238               Y
     solar..........................
    Small--Compressed air--grid.....              1,418               Y
    Small--Compressed air--generator              2,069               Y
    Medium--Electric controllers -                  216               Y
     grid...........................
    Medium--Electric controllers--                  309               Y
     solar..........................
    Medium--Compressed air--grid....              1,250               Y
    Medium--Compressed air--                      1,571               Y
     generator......................
    Large--Electric controllers -                   233               Y
     grid...........................
    Large--Electric controllers--                   357               Y
     solar..........................
    Large--Compressed air--grid.....              1,033               Y
    Large--Compressed air--generator              1,432               Y
------------------------------------------------------------------------
\a\ For the production segment, the owners and operators realize the
  savings for the natural gas that not emitted and lost. The cost
  effectiveness values shown do not consider these savings. Note that
  the consideration of savings does not impact whether the cost
  effectiveness of any of these options falls within the ranges
  considered reasonable by the EPA.

    As shown in Table 28, all options evaluated, with the exception of 
an instrument air system driven by a generator at a small model plant, 
have cost effectiveness values within the range that the EPA considers 
reasonable for methane.
    Further, as discussed at length above in section IV.D.1.b.iii, the 
EPA finds that these controller technologies not driven by natural gas 
are technically feasible in locations with and without electrical 
power. Owners and operators can use natural gas-driven low or high 
bleed controllers or intermittent controllers, provided the emissions 
are collected and routed through a CVS to a process. Finally, owners 
and operators have the option of using natural gas-driven self-
contained controllers.
    Secondary impacts from these options, particularly from the use of 
instrument air systems, are indirect, variable, and dependent on the 
electrical supply used to power the compressor. As discussed above, 
this would result in an increase in electricity needs and minimal 
emission increases. As discussed above, the use of a generator to power 
an instrument air system will result in emissions of two criteria 
pollutants--CO and CO2. However, the comparison in the 
CO2 equivalent emissions shows that even with the secondary 
emissions from the generator, there is a substantial reduction in 
CO2 equivalent emissions.
    In light of the above, we find that the BSER for reducing methane 
emissions from existing natural gas-driven controllers in the 
production and transmission and storage segments of the industry to be 
the use of controllers that have a methane emission rate of zero. This 
option results in a 100 percent reduction of emissions of methane. 
Therefore, for EG OOOOc, we are proposing to require that each 
pneumatic controller affected facility be designed and operated with a 
methane emission rate of zero for all pneumatic controllers in the 
production and transmission and storage segments of the source 
category, with the exception discussed below.
    As discussed above for new sources, we did not re-evaluate BSER for 
sites in Alaska that do not have access to electricity and are 
proposing the same requirements as in the November 2021 proposal. 
Similarly, we did not re-evaluate BSER for pneumatic controllers at 
existing natural gas processing plants. Therefore, the November 2021 
BSER determination of zero-emission controllers at natural gas 
processing plants is retained in this supplemental proposal.
    The proposed standards and other requirements for existing 
pneumatic controller designated facilities under EG OOOOc are the same 
as described above for new pneumatic controller affected facilities 
under the NSPS OOOOb.
d. Additional Comments
    There were two additional topics raised in the public comments that 
are discussed in this section: (1) The potential exemption of small 
sites with low production and/or a low number of controllers, and (2) 
issues associated with the supply chain.

[[Page 74769]]

i. Small Site Exemptions.
    Several commenters requested that the EPA include an exemption for 
small sites with low production and/or a low number of pneumatic 
controllers. The commenters provided a range of pneumatic controllers 
that they felt represented a reasonable cut-off, ranging from 3 to 30 
controllers.
    The EPA notes that the cost effectiveness values for the smallest 
model plant, which includes 1 high-bleed, 1 low-bleed, and 2 
intermittent vent controllers, were $181 and $238 per ton of methane 
reduced for electric controllers and solar controllers, respectively. 
These cost effectiveness values are well within the ranges considered 
to be reasonable by the EPA. We also performed an analysis of the cost 
effectiveness of the use of electric controllers and solar-powered 
controllers at sites with a single controller. For sites with only one 
high-bleed controller, the cost effectiveness was estimated to be $379 
and $437 per ton of methane reduced for electric and solar-powered 
controllers, respectively. For a site with one intermittent vent 
controller, the cost effectiveness values were estimated as $913 per 
ton for electric controllers, and $1,053 per ton for solar-powered 
controllers. For a site with one low-bleed controller, the cost 
effectiveness values were $1,181 per ton for electric controllers and 
$1,363 per ton for solar-powered controllers. As all of these cost 
effectiveness values are within the range considered reasonable for 
methane by the EPA, this analysis does not support an exemption for 
sites with low numbers of pneumatic controllers.
    One commenter stated that even at the current prices for natural 
gas, it would take the average low-production natural gas well about 
six years of all of its profits to pay for the electric grid option and 
more than that for the solar option. The commenter added that for a 
Pennsylvania well site, the time period would be 70 or more years.\155\ 
This commenter did not provide details of their analysis. While the EPA 
recognizes that that impacts on profitability are generally not 
considered in determining BSER, we are interested in the details of the 
analysis of profit margins at low production wells. Specific to this 
information provided by the commenter, dividing the total estimated 
capital investment of an electric controller system for the small model 
plant ($20,593) by six years results in $3,400 per year. If it is 
assumed that this capital investment is financed for six years at a 7 
percent interest rate, this cost would be around $4,300 per year, which 
equates to around $360 per month. The EPA is interested in learning 
whether this amount represents typical profit margins for low 
production wells.
---------------------------------------------------------------------------

    \155\ See Document ID No. EPA-HQ-OAR-2021-0317-0814.
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    Another commenter added that the cost of converting to an 
electronic controller or instrument air system will likely result in 
the shut-in of many small, low-production well sites. These sites have 
a remaining useful life that will be cut short by the proposed rule's 
pneumatic controller requirements.\156\
---------------------------------------------------------------------------

    \156\ See Document ID No. EPA-HQ-OAR-2021-0317-0777.
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    The EPA notes that the implementing regulations for emission 
guidelines contained in 40 CFR part 60, subpart Ba include provisions 
that allow states to develop a less stringent standard taking into 
consideration factors such as the remaining useful life of such source. 
For more information on remaining useful life and other factors 
considerations, see section V.C of this preamble.
ii. Supply Chain Issues
    In light of the proposal to require zero-emission pneumatic 
controllers for both new and existing sources, the EPA would like to 
address several comments it received and solicit related information. 
One commenter predicted that the requirements will likely generate 
supply chain shortages and the small operators will be last to procure 
the necessary equipment at the highest price.\157\ Another commenter 
stated that the EPA has not adequately considered the impacts of the 
current supply chain interruptions on the ability of operators to 
comply with the rule. Specialized equipment, such as air compressors, 
electric controllers, and equipment needed to retrofit facilities have 
been particularly hard-hit by supply chain constraints related to 
COVID-19. This commenter reported that owners and operators have 
already experienced delays of several months in acquiring equipment to 
retrofit facilities to instrument air, all prior to the EPA proposal, 
and that the increased demand for that equipment given proposed rule 
requirements would only exacerbate the challenges associated with 
acquiring that equipment.\158\ For existing sources, the EPA points out 
that several years will pass between the time EG OOOOc is finalized and 
the compliance dates for state rules, thus allowing a substantial 
amount of time for adjustments in the supply chain. While the 
commenters primarily focused on potential supply chain issues related 
to requiring the conversion to zero emissions controllers at existing 
sources, the EPA also understands that the promulgation of NSPS OOOOb 
could also result in a spike in the demand. In light of these comments, 
the EPA is specifically requesting additional comment on the 
availability of zero-emission pneumatic controller systems not powered 
by natural gas due to supply chain constraints or other reasons.
---------------------------------------------------------------------------

    \157\ See Document ID No. EPA-HQ-OAR-2021-0317-0814.
    \158\ See Document ID No. EPA-HQ-OAR-2021-0317-0743.
---------------------------------------------------------------------------

E. Pneumatic Pumps

    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. Natural gas-driven pneumatic pumps emit methane and VOCs 
as part of their normal operation. Detailed information on pneumatic 
pumps, including their functions, operations, and emissions, is 
provided in the preamble for the November 2021 proposal (86 FR 63224-
63226; November 15, 2021).
1. NSPS OOOOb
a. November 2021 Proposal
    In the November 2021 proposal, a pneumatic pump affected facility 
was defined as each natural gas-driven diaphragm or piston pump in any 
segment of the source category. The proposed definition of an affected 
facility excluded lean glycol circulation pumps that rely on energy 
exchange with the rich glycol from the contractor.
    For pneumatic pumps in the production and transmission and storage 
segments, the November 2021 proposal would have required that the 
emissions be routed to an existing control device that achieves 95 
percent control of methane and VOCs, or to route the emissions to an 
existing VRU and to a process. This proposed standard would have 
covered both diaphragm and piston pumps. The proposed rule did not 
propose to require that a new control device be installed. At natural 
gas processing plants, the proposed rule would have required the 
prohibition of methane and VOC emissions from pneumatic pumps.
    The BSER analysis that led to the November 2021 proposed pneumatic 
pump requirements for the production

[[Page 74770]]

and transmission segments concluded that the cost effectiveness for 
routing to an existing control device was reasonable. The EPA also 
concluded that it was not cost-effective to require the owner or 
operator of a pneumatic pump to install a new control device or process 
onsite to capture emissions solely for this purpose.
    The EPA also evaluated pneumatic pumps that are not powered by 
natural gas. Specifically, the types of pumps evaluated were electric 
pumps, solar-powered pumps, and pumps powered by compressed air. 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 assumed that electrical power was available onsite. 
We noted that commenters have raised concerns in the past regarding 
solar-powered pneumatic pumps, which have technical limitations that do 
not make them universally feasible for locations without access to 
electrical power. In November 2021, we did not have information that 
such limitations had been overcome, and we were therefore unable to 
conclude that pumps not driven by natural gas represented BSER at that 
time. We solicited comment on this issue to better understand whether 
options that do not use natural gas are technically feasible at sites 
without electrical power. We also solicited comment on an approach that 
would subcategorize pneumatic pumps located at production and 
transmission and storage sites based on availability of electricity and 
would then set separate standards for each subcategory.
    Since all natural gas processing plants have access to electrical 
power, we only evaluated compressed air systems for this segment. The 
cost effectiveness of these systems was found to be in the range 
considered to be reasonable by the EPA, and we therefore concluded that 
BSER was pneumatic pumps that are not driven by natural gas.
b. Changes to Proposal and Rationale
    The proposed NSPS OOOOb requirements in this supplemental proposal 
differ from the November 2021 proposal in several ways, starting with 
the affected facility definition. As noted above, in the November 2021 
proposal, a pneumatic pump affected facility was defined as each 
natural gas-driven pneumatic pump. In this supplemental proposal, a 
pneumatic pump affected facility is defined as the collection of all 
natural gas-driven pneumatic pumps at a site.
    After considering comments on the emissions standards, as well as 
the information submitted in response to our specific solicitations for 
information, the EPA is now proposing a zero-emissions standard for 
pneumatic pump affected facilities in all segments of the industry. 
Specifically, the EPA is proposing that pneumatic pumps not driven by 
natural gas be used. This is a significant change from the November 
2021 proposal, which would have required that emissions from pneumatic 
pump affected facilities be routed to control or to a process, but only 
if an existing control or process was on site.
    The proposed rule recognizes that at sites without access to 
electricity, there could be situations where it is technically 
infeasible to use a pump that is not driven by natural gas. As a 
result, the EPA is proposing to include a tiered structure in the rule 
that would allow flexibility based on site-specific conditions. At 
sites without access to electricity, if a demonstration is made that it 
is technically infeasible to use a pneumatic pump that is not driven by 
natural gas, the rule would allow the use of a natural gas-driven pump, 
provided that the emissions are captured and routed to a process, which 
EPA understands to achieve 100 percent reduction of methane and VOC. 
Such an infeasibility determination is not allowed if the site has 
access to electricity. This means the proposed rule would prohibit the 
use of natural gas-driven pumps at sites with access to electricity.
    At sites without access to electricity for which the owner or 
operator has demonstrated that it is technically infeasible to utilize 
a pneumatic pump not driven by natural gas, an owner or operator may 
also demonstrate that it is technically infeasible to capture the 
pneumatic pump's emissions and route them to a process. Where routing 
to a process is infeasible, the resulting requirement for emissions 
control depends on the number of natural gas-driven diaphragm pumps at 
the site. If there are four or more natural gas-driven pumps at the 
site, the proposed rule would require that the emissions from all pumps 
at the site be collected and be routed to a control device that 
achieves 95 percent reduction of methane and VOC. If there are less 
than four natural gas-driven diaphragm pumps at the site without access 
to electricity, the proposed requirements for pumps at the site would 
be the same as in the November 2021 proposal, i.e., route to an 
existing control device that achieves 95 percent emissions reductions.
    Details on the proposed pneumatic pump requirements are provided in 
section IV.D.1.c. The following sections provide the rationale for the 
significant changes discussed in this section.
i. Changes to Affected Facility, Modification, and Reconstruction
    As previously noted, the pneumatic pump affected facility 
definition changed from being a single pump in the November 2021 
proposal to the collection of pumps at a site in this supplemental 
proposal. In this supplemental proposal, a pneumatic pump affected 
facility is defined as the collection of all natural gas-driven 
pneumatic pumps at a site. As we advanced our evaluation of the control 
measures to reduce methane and VOC emissions from pneumatic pumps, it 
became apparent that most of the measures to reduce or eliminate 
emissions are site-wide solutions. For instance, a compressed air 
system installed at a site would be used to power all pneumatic pumps 
at the site, not just one, which would alleviate the need for a 
separate system for each pump. In fact, the cost analysis for the 
November 2021 proposed rule for compressed air systems was conducted on 
a ``model plant'' site-wide basis. Similarly, emissions from all pumps 
at a site would be routed to a single control device and would 
therefore not require the installation of a control device for each 
pump. We are specifically soliciting comment on this proposed change to 
the definition of a pneumatic pump affected facility from an individual 
pump to the collection of all natural gas-driven pneumatic pumps at a 
site.
    In addition, some of the means of powering a pneumatic pump without 
the use of natural gas can also be used to power pneumatic controllers. 
While our updated BSER analyses for pneumatic pumps and pneumatic 
controllers evaluated the cost effectiveness of these sources 
independently, the shared usage of solutions for the two sources, such 
as compressed air systems, solar-powered systems, or generators, will 
result in even lower overall site-wide cost effectiveness values.
    Under the previous approach in which EPA assessed each pump on an 
individual basis, the installation or replacement of a pneumatic pump 
would have resulted in the pump being a new source and an affected 
facility subject to NSPS OOOOb. In 40 CFR 60.14(a), modification is 
defined as ``any physical or operational change to an existing facility 
which results in an increase in the emission rate to the atmosphere of 
any pollutant.'' In order to clarify what constitutes a

[[Page 74771]]

modification for the collection of all pneumatic pumps at a site, the 
supplemental proposed rule specifies that if one or more pneumatic 
pumps is added to the site such that the total number of pumps 
increases, such addition constitutes a modification because it 
represents a physical change that results in an increase in emissions. 
Therefore, the collection of pneumatic pumps at the site would become a 
pneumatic pump affected facility. The EPA believes that owners and 
operators will implement zero-emission pumps across a site when a 
modification occurs because converting a single zero-emitting device 
typically requires a conversion of all devices at the facility. The EPA 
solicits comment on the ways in which a modification to a pneumatic 
pump affected facility would occur in light of the affected facility 
definition proposed herein, which includes the collection of all 
natural gas-driven pneumatic pumps at a site.
    Analogous to the discussion above regarding reconstruction for 
pneumatic controllers in section IV.D.1.b.i, the definition of the 
pneumatic pump affected facility is the collection of natural gas-
driven pneumatic pumps at a site. As with pneumatic controllers, the 
cost that would be required to construct a ``comparable entirely new 
facility'' under 40 CFR 60.15(b)(1) would be the cost of replacing all 
existing pumps with new pumps. Because individual pumps are likely to 
have comparable replacement costs, it is reasonable to assume that 
there would be a one-to-one correlation between the percentage of pumps 
being replaced at a site and the percentage of the fixed capital cost 
that would be required to construct a comparable entirely new facility.
    Accordingly, we are proposing to include a second, simplified 
method of determining whether a pump replacement project constitutes 
reconstruction under 40 CFR 60.15(b)(1) whereby reconstruction may be 
considered to occur whenever greater than 50 of the number of existing 
onsite pumps are replaced.\159\ As with controllers, the EPA believes 
that allowing owners or operators to determine reconstruction by 
counting the number of pumps replaced is a more straightforward option 
than requiring owners and operators to provide cost estimate 
information. By providing this option, the EPA intends to reduce the 
administrative burden on owners and operators, as well as on the 
implementing agency reviewing the information. Owners and operators 
would be able to choose whether to use the cost-based criterion or the 
proposed number-of-pumps criterion. No matter which option an owner or 
operators chooses to use, the remaining provisions of 40 CFR 60.15 
apply--namely, 40 CFR 60.15(a), the technological and economical 
provision of 40 CFR 60.15(b)(2), and the requirements for notification 
to the Administrator and a determination by the Administrator in 40 CFR 
60.15(d), (e) and (f). The EPA is proposing that the standard in 40 CFR 
60.15(b)(1) specifying that the ``fixed capital cost of the new 
components exceeds 50 percent of the fixed capital cost that would be 
required to construct a comparable entirely new facility'' can be met 
through a showing that 50 percent or more of the number of existing 
onsite pumps are replaced. Therefore, upon such a showing, an owner or 
operator may demonstrate compliance with the remaining provisions of 40 
CFR 60.15 that reference the ``fixed capital cost'' criterion.
---------------------------------------------------------------------------

    \159\ Adding this method of determining ``reconstruction'' for 
pneumatic pumps is in accordance with 40 CFR 60.15(g), which states 
that ``[i]ndividual subparts of this part [``Reconstruction''] may 
include specific provisions which refine and delimit the concept of 
reconstruction set forth in this section.''
---------------------------------------------------------------------------

    The same logic and rationale discussed above in section IV.D.1.b.i 
for applying a 2-year rolling aggregation period for controller 
replacements also applies for pneumatic pumps. Therefore, we are 
proposing the same 2-year rolling period as the appropriate aggregation 
period to define a proposed replacement program time frame. Thus, the 
EPA proposes to count toward the greater than 50 percent reconstruction 
threshold all pumps replaced pursuant to all continuous programs of 
reconstruction which commence (but are not necessarily completed) 
within any 2-year rolling period following proposal of these standards. 
In the Administrator's judgment, the 2-year rolling period provides a 
reasonable method of determining whether an owner of an oil and natural 
gas site with pneumatic pumps is actually proposing extensive 
controller replacement, within the EPA's original intent in 
promulgating 40 CFR 60.15. As explained in greater detail in section 
IV.D.1.b.i, the EPA is soliciting comment on several aspects of the 
proposed reconstruction definition for pneumatic pumps and pneumatic 
controllers and refers commenters to that section for a description of 
the specific information requested.
    The following scenarios are examples of the application of these 
proposed requirements for a site with access to electricity that has 
four natural gas-driven pneumatic pumps. Scenario 1--One of the four 
pumps is replaced at any given time. The collection of pumps at the 
site would not be a pneumatic pump affected facility as this action is 
not a modification or reconstruction. Scenario 2--Three of the four 
pumps are replaced at the same time. This would constitute 
reconstruction (replacement of greater than 50 percent of the pumps), 
so the four pumps (i.e., the ``collection'' of pumps at the site) would 
be a pneumatic pump affected facility. This affected facility would 
then be subject to the zero emissions standard, meaning that all pumps 
at the site, including the three new pumps and the one existing pump, 
cannot be driven by natural gas. Under Scenario 2, the one existing 
pump would need to be replaced or converted so that it is not powered 
by natural gas. Scenario 3--one pneumatic pump is replaced in February 
and two more are replaced in December of the same year. This would 
represent reconstruction (because more than 50 percent of the total 
number of pumps are being replaced over a 2-year period), so the four 
pumps (i.e., the ``collection'' of pumps at the site) would be a 
pneumatic pump affected facility at the time the two pumps were 
replaced in December. This affected facility would then be subject to 
the zero-emissions standard, meaning that all four pumps would not be 
allowed to be driven by natural gas. Scenario 4--An additional 
pneumatic pump is added at any given time. This addition would 
represent a modification since it represents a physical change and 
would result in an increase in emissions. The five pumps would be a 
pneumatic pump affected facility and all five pumps would need to be 
powered in a manner other than natural gas.
ii. Changes to the Standard
    As discussed above, we solicited comment in the November 2021 
proposal on two key issues related to the proposed standard and BSER 
determination. These were: (1) An approach that would involve 
subcategorizing pneumatic pumps located at production and transmission 
and storage segments based on availability of electricity, and then 
developing separate standards for each subcategory, and (2) the 
technical feasibility of using pneumatic pumps not powered by natural 
gas at sites without electrical power.
    Regarding the first issue, several commenters supported the 
approach of subcategorizing based on access to electrical power, and 
then determining BSER for pneumatic pumps separately for sites with and 
without access to

[[Page 74772]]

electrical power. One of these commenters noted that the availability 
of electricity is a significant and constraining factor that is within 
the EPA's authority to consider in subcategorization.\160\
---------------------------------------------------------------------------

    \160\ See Document ID No. EPA-HQ-OAR-2021-0317-0938.
---------------------------------------------------------------------------

    The comments were mixed concerning the feasibility of options that 
do not use natural gas-driven pneumatic pumps at remote sites without 
access to electrical power. Several commenters maintain that zero-
emission pneumatic pumps are technically infeasible at sites without 
electricity. For example, one commenter who voiced support for the use 
of non-natural gas driven pumps as an option at sites where it is 
technically feasible indicated that requiring these pumps at many of 
their remote sites would be ``burdensome at best and would force site 
shutdown in many cases.'' \161\ Another commenter stated that onsite 
solar generation paired with battery storage as an alternative to grid 
electricity systems are currently uncommon and unreliable. According to 
the commenter, use of these systems would likely increase the frequency 
of facility upsets, which would increase safety risks such as 
overpressure events and spills. The commenter concluded that onsite 
solar should therefore not be deemed an available technology.\162\ 
Other commenters provided specific examples of where pneumatic pumps 
not driven by natural gas, particularly solar-powered pumps, would 
likely not be technically feasible. Examples of the situations cited 
included locations with very cold temperatures, extended periods of 
cloud cover, and heavy snow load.
---------------------------------------------------------------------------

    \161\ See Document ID No. EPA-HQ-OAR-2021-0317-0463.
    \162\ See Document ID No. EPA-HQ-OAR-2021-0317-0793.
---------------------------------------------------------------------------

    However, many commenters reported that options that do not use 
natural gas-driven pneumatic pumps are available at sites without 
access to grid electricity systems, and that their use has been 
demonstrated. One of these commenters noted that in addition to solar-
powered pumps, thermal electric generators or methanol fuel cells have 
been used to increase power at sites with high demand.\163\ Another 
commenter is aware of retrofits at remote locations that have no 
electrical power in which natural gas is used to generate electricity 
to run pumps directly or to power air compressors that drive pneumatic 
pumps.\164\ The EPA is requesting information regarding the 
characteristics of sites where thermal electric generators, methanol 
fuel cells, or other means to boost power for solar driven pneumatic 
pumps are needed. The EPA is also interested in costs for those 
systems.
---------------------------------------------------------------------------

    \163\ See Document ID No. EPA-HQ-OAR-2021-0317-0844.
    \164\ See Document ID No. EPA-HQ-OAR-2021-0317-0765.
---------------------------------------------------------------------------

    Two commenters, who are also equipment vendors, confirmed the 
successful implementation of technologies to utilize pneumatic pumps 
not driven by natural gas at remote locations without the access to the 
grid. One has deployed solar-driven pneumatic pumps and air compressors 
in many states throughout the southwestern and northwestern U.S., 
including a remote location in Wyoming that experienced temperatures 
down to minus 11 degrees Centigrade ([deg]C).\165\ The second vendor 
reported that their standalone power generators have been deployed at a 
number of sites across the country to power pneumatic pumps.\166\
---------------------------------------------------------------------------

    \165\ See Document ID No. EPA-HQ-OAR-2021-0317-0838.
    \166\ See Document ID No. EPA-HQ-OAR-2021-0317-0823.
---------------------------------------------------------------------------

    In our analysis for the November 2021 proposal, we evaluated the 
costs and impacts of electric pumps run from the grid, solar-powered 
pumps, and compressed air systems to power the pumps. No significant 
comments were received on this 2021 analysis; therefore, the essential 
elements of the analysis and results remain the same.
    Baseline Emissions. The baseline emission estimates were calculated 
assuming a bleed rate of 2.48 scfh for natural gas-driven piston pumps 
and 22.45 scfh for natural gas-driven diaphragm pumps. Based on these 
natural gas bleed rates, assuming that natural gas bleeds from the pump 
for 8,760 hours per year and using the segment-specific gas 
compositions developed during the 2012 NSPS, the baseline emissions 
were estimated as provided in Table 21. More information on these 
calculations is provided in the Technical Support Document for this 
rulemaking.
    The baseline emission analysis was conducted for six representative 
sites: (1) A single diaphragm pump, (2) a single piston pump, (3) one 
diaphragm pump and one piston pump, (4) two diaphragm pumps and two 
piston pumps, (5) 10 diaphragm pumps and 10 piston pumps, and (6) 50 
diaphragm pumps and 50 piston pumps. All representative sites were not 
evaluated for all three sectors, as it is not expected that they would 
be applicable. Specifically, the two largest sites with 10 and 100 
total pumps were not evaluated for the production and transmission and 
storage segments. For the processing plant segment, since it is 
expected that multiple pumps would be at each site, only representative 
sites 4, 5, and 6 were evaluated. The following table provides the 
baseline emissions for each type of representative facility.

                                                      Table 29--Baseline Pneumatic Pump Emissions (Tons per Year) for Representative Sites
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                            # of Pumps                      Production                      Processing                 Transmission/storage
                           Rep Site #                            -------------------------------------------------------------------------------------------------------------------------------
                                                                     Diaphragm        Piston          Methane           VOC           Methane           VOC           Methane           VOC
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1...............................................................               1               0            3.46            0.96                n/a                          4.5           0.125
2...............................................................               0               1            0.38            0.11                n/a                         0.50           0.014
3...............................................................               1               1            3.84            1.07                n/a                          5.0            0.14
                                                                                                                                 --------------------------------
4...............................................................               2               2            7.68            2.14            7.68            2.14            10.0            0.28
                                                                                                 --------------------------------                                -------------------------------
5...............................................................              10              10                n/a                         38.4            10.7                n/a
6...............................................................              50              50                n/a                        192.0            53.4                n/a
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

    Cost Analysis for Options That Do Not Use Natural Gas-Driven 
Pneumatic Pumps. The EPA evaluated the following pump options that do 
not use natural gas: electric pumps, solar-powered pumps, and 
instrument air systems that produce compressed air to power the pumps. 
All three options were evaluated for pneumatic pumps in the production 
and transmission and storage segments. For the processing segment, only 
instrument air systems

[[Page 74773]]

were evaluated because it is expected that all processing plants have 
access to electrical power and have multiple pumps at the site.
    The following paragraphs provide the estimated costs for electric 
pumps, solar-powered pumps, and instrument air systems. The EPA is not 
aware of differences between the oil and natural gas industry segments 
that would result in the different costs for these options between 
segments. These paragraphs provide capital costs and total annual 
costs. For all of these options, the capital recovery cost component of 
the annual cost is based on a 7 percent interest rate and an equipment 
life of 10 years.
    The capital and installation cost of an electric pump using 
electricity from the grid is estimated to be $5,219. The total annual 
costs, including capital recovery and an estimated operation and 
maintenance cost of $329 per year, yields a total annual cost per 
electric pump of $1,072.
    For solar-powered pumps, the estimated capital cost, including 
installation, is $2,501 per pump. It is assumed that the annual 
operation and maintenance is no greater than a natural gas-driven pump, 
so the total annual cost is the capital cost of $356 per year.
    For electric pumps and solar-powered pumps, the cost information is 
assessed on an individual pump basis. While it is expected that the 
cost per pump would be less where there are more pumps on site, we do 
not have information on these cost advantages. Therefore, our estimate 
of the site-wide costs and emission reductions would simply be the 
multiple of our per pump costs and emission reductions multiplied by 
the number of pumps at the site. Thus, the cost effectiveness for 
representative sites 3 and 4 is the same. The EPA is requesting 
information on the costs of site-wide electric and solar-powered pump 
solutions.
    Instrument air system costs were estimated for small, medium, and 
large compressors. The small compressor was assumed to have an air 
capacity of 135 scfh, while the medium and large had capacities of 562 
and 1,350 scfh, respectively. The estimated capital (including 
installation) costs for these three sizes of instrument air systems are 
$6,742 for the small system, $33,699 for the medium system, and $59,308 
for the large system. The estimated annual costs, including capital 
recovery, labor for operation and maintenance, and electricity, are 
$11,295 for the small system, $36,264 for the medium system, and 
$81,350 for the large system. In the estimation of impacts for the 
representative sites described above, the small system costs were used 
for representative sites 1, 2, 3, and 4; the medium system for 
representative site 5; and the large system for representative site 6.
    Since all of these options do not use natural gas to drive the 
pneumatic pump, their use results in a 100 percent reduction in methane 
and VOC emissions from the baseline levels shown in Table 21 above. 
Using the annual total annual costs and these emission reductions, we 
calculated the cost effectiveness for each zero-emission option for 
each representative site. Cost effectiveness was calculated on a single 
pollutant basis, where the total annual cost was applied entirely to 
the reduction of each pollutant. Cost effectiveness was also calculated 
on a multi-pollutant basis, where half the cost of control is assigned 
to the methane reduction and half to the VOC reduction.
    The estimated cost effectiveness values for the options that do not 
use natural gas-driven pneumatic pumps are provided in Table 30. In 
addition to the cost effectiveness values, Table 30 provides a 
conclusion as to whether the estimated cost effectiveness value is 
within the range that the EPA has typically considered to be 
reasonable. The ``overall'' reasonableness determination is classified 
as ``yes'' if the cost effectiveness of either methane or VOC is within 
the range that the EPA considers reasonable for that pollutant, or if 
both the methane and VOC cost effectiveness values are without the 
range that the EPA considers reasonable on a multipollutant basis.

                     Table 30--Summary of Cost Effectiveness for Pneumatic Pump Options That Do Not Use Pumps Driven by Natural Gas
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                              Cost Effectiveness ($/ton) \a\--Reasonable?
                                    ----------------------------------------------------------------------------------------------
  Segment Option--  Representative                  Single pollutant                                Multipollutant                      Overall \a\
                Site                ----------------------------------------------------------------------------------------------
                                             Methane                   VOC                  Methane                  VOC
--------------------------------------------------------------------------------------------------------------------------------------------------------
Production Segment:
    Electric Pumps--Single           $310-Y................  $1,115-Y..............  $115-Y...............  $557-Y...............  Y
     Diaphragm.
    Electric Pumps--Single Piston..  1,632-Y...............  5,869-Y...............  816-Y................  2,934-Y..............  Y
    Electric Pumps--Multiple         441-Y.................  1,585-Y...............  220-Y................  793-Y................  Y
     Pumps\b\.
    Solar Pumps--Single Diaphragm..  103-Y.................  370-Y.................  51-Y.................  185-Y................  Y
    Solar Pumps--Single Piston.....  937-Y.................  3,371-Y...............  469-Y................  1,686-Y..............  Y
    Solar Pumps--Multiple Pumps\b\.  185-Y.................  667-Y.................  93-Y.................  334-Y................  Y
    Instrument Air--Single           3,264-N...............  11,743-N..............  1,632-Y..............  5,871-Y..............  Y
     Diaphragm.
    Instrument Air--Single Piston..  29,724-N..............  106,921-N.............  14,682-N.............  53,461-N.............  N
    Instrument Air--1 Diaphragm/1    2,941-N...............  10,581-N..............  1,471-Y..............  5,290-Y..............  Y
     Piston.
    Instrument Air--2 Diaphragm/2    1,471-Y...............  5,290-Y...............  735-Y................  2,645-Y..............  Y
     Piston.

[[Page 74774]]

 
Processing Segment:
    Instrument Air--2 Diaphragm/2    1,471-Y...............  5,290-Y...............  735-Y................  2,645-Y..............  Y
     Piston.
    Instrument Air--10 Diaphragm/10  944-Y.................  3,397-Y...............  472-Y................  1,699-Y..............  Y
     Piston.
    Instrument Air--50 Diaphragm/50  424-Y.................  1,524-Y...............  212-Y................  762-Y................  Y
     Piston.
Transmission and Storage Segment:
    Electric Pumps--Single           237-Y.................  8,563-N...............  119-Y................  4,281-Y..............  Y
     Diaphragm.
    Electric Pumps--Single Piston..  1,249-Y...............  45,083-N..............  624-Y................  22,541-N.............  Y
    Electric Pumps--Multiple Pumps   337-Y.................  12,177-N..............  169-Y................  6,088-N..............  Y
     \b\.
    Solar Pumps--Single Diaphragm..  79-Y..................  2,844-Y...............  39-Y.................  1,422-Y..............  Y
    Solar Pumps--Single Piston.....  717-Y.................  25,897-N..............  359-Y................  12,948-N.............  Y
    Solar Pumps--Multiple Pumps\b\.  142-Y.................  5,125-Y...............  71-Y.................  2,563-Y..............  Y
    Instrument Air--Single           2,499-N...............  90,206-N..............  1,249-N..............  45,103--N............  N
     Diaphragm.
    Instrument Air--Single Piston..  22,751-N..............  821,348-N.............  11,376-N.............  410,674-N............  N
    Instrument Air--1 Diaphragm/1    2,251-N...............  81,279-N..............  1,126-Y..............  40,640-N.............  N
     Piston.
    Instrument Air--2 Diaphragm/2    1,126-Y...............  40,640-N..............  563-Y................  20,320-N.............  Y
     Piston.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ For the production and processing segments, the owners and operators realize the savings for the natural gas that was not emitted and lost. The cost
  effectiveness values shown do not consider these savings. Note that the consideration of savings does not impact whether the cost effectiveness of any
  of these options falls within the ranges considered reasonable by the EPA.
\b\ For overall cost effectiveness to be considered reasonable, either the cost effectiveness of methane or VOC on a single pollutant basis must be
  within the ranges considered reasonable by the EPA, or the cost effectiveness of both methane and VOC on a multipollutant basis must be within the
  ranges considered reasonable by the EPA.
\c\ For multiple pump scenarios, an equal number of diaphragm and piston pumps is assumed.

    While the costs for electric pumps and instrument air systems 
assume access to electrical power (that is, access to the grid), solar-
powered pumps can be utilized at many remote sites that do not have 
access to electrical power. Instrument air systems can also be utilized 
at sites without access to the electricity grid but would require the 
installation and operation of a generator. These generators could be 
powered by engines fueled by solar energy, natural gas, or diesel. 
While such systems are technically a viable option at these remote 
sites, we did not have detailed cost information available to include 
these systems in our analysis. One commenter provided estimated costs 
ranging from $60,000 to over $200,000 for an instrument air system 
driven by a natural gas generator.\167\ The commenter also provided an 
estimate of $250,000 for an instrument air system powered by solar 
energy. However, the focus of the comments and these cost estimates was 
pneumatic controllers, not pumps. The EPA is specifically requesting 
information on whether these costs are representative of systems that 
could be used to power compressed air-driven pneumatic pumps, as well 
as comments on whether a single generator or solar system could be used 
to power both pneumatic controllers and pneumatic pumps.
---------------------------------------------------------------------------

    \167\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.
---------------------------------------------------------------------------

    Proposed BSER Conclusion. As demonstrated in the analysis, there 
are pneumatic pump options that do not use natural gas for which the 
cost effectiveness is within the ranges considered to be reasonable by 
the EPA. These types of pumps can be utilized at sites with access to 
grid electricity as well as at remote sites that do not have this 
access.
    This BSER conclusion is consistent with the EPA's findings in 2021. 
However, at that time we were unable to conclude that pumps that do not 
use natural gas represented BSER due to our inability to conclude that 
technical limitations previously identified had been overcome. As 
summarized above, several commenters continue to

[[Page 74775]]

maintain that there are significant technical limitations, particularly 
with solar-powered pneumatic pumps. However, other commenters provided 
evidence that pneumatic pumps not driven by natural gas are available 
and in use in the industry.
    Under CAA Section 111(b), the EPA must determine that the BSER has 
been ``adequately demonstrated.'' The EPA concludes that pneumatic pump 
systems that do not use natural gas have met this standard at sites 
both with and without access to grid electricity. In addition, as 
discussed above, we have concluded that there are system options 
available at sites in all segments of the industry that have cost 
effective values considered reasonable by the EPA.
    Secondary impacts from these non-natural gas-driven pumps, 
particularly from the use of instrument air systems, are indirect, 
variable, and dependent on the electrical supply used to power the 
compressor. The secondary impacts resulting from the increase in 
electricity needed from the grid to power compressors for instrument 
air were discussed above for pneumatic controllers. These also 
represent the impacts that would occur for compressors used to provide 
instrument air for pneumatic pumps. However, a single compression 
system, appropriately sized, could power both pneumatic controllers and 
pumps at a site, meaning that the electricity usage and resulting 
secondary impacts would not necessarily be doubled. 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 
all segments of the industry is the use of pneumatic pumps that do not 
use natural gas as a driver. This option results in a 100 percent 
reduction of direct emissions for both methane and VOC, or zero methane 
and VOC emissions. Therefore, for NSPS OOOOb, we are proposing to 
require a natural gas emission rate of zero for all pneumatic pumps in 
the source category.
    One request for comments that the EPA solicited in November 2021 
was related to the potential subcategorization of pumps based on access 
to grid electrical power. Because we have determined that the 
requirement to use zero-emission pumps that are not powered by natural 
gas is BSER for all sites, regardless of whether the site has access to 
electrical power, we have decided that subcategorization is not 
necessary.
    Technical Infeasibility Situations. While we conclude that zero-
emission pneumatic pumps not powered by natural gas are adequately 
demonstrated as BSER, we understand that there may be specific 
conditions at sites without access to electricity that result in 
situations where it may be technically infeasible to utilize a non-
natural gas-driven pump. Therefore, we also analyzed alternatives that 
could be incorporated into NSPS OOOOb in these instances. Note that 
because we have concluded that it should always be technically feasible 
for sites with access to electricity to utilize zero-emission pneumatic 
pumps that are not driven by natural gas, these alternatives would only 
be available at sites that do not have access to electricity.
    First, we analyzed capturing the natural gas emissions from the 
pneumatic pump through venting and routing them to an existing process. 
The costs associated with this option are a capital cost of $6,102 with 
an annual cost of $869 (capital recovery using 7 percent interest for 
10 years). The cost effectiveness for a single diaphragm pump in the 
production segment, assuming 100 percent capture, was $251 per ton of 
methane removed ($79 per ton with savings) and $903 per ton of VOC 
removed ($284 per ton with savings). On a multipollutant basis, these 
cost effectiveness values were $126 per ton of methane ($39 per ton 
with savings) and $452 per ton of VOC ($142 per ton with savings). For 
a single piston pump, the cost effectiveness was $2,286 per ton of 
methane removed ($2,114 with savings) and $8,224 per ton of VOC ($7,604 
with savings). On a multipollutant basis, these cost effectiveness 
values were $1,143 per ton of methane ($1,057 per ton with savings) and 
$4,112 per ton of VOC ($3,802 per ton with savings).
    For the representative site 3 (with one diaphragm piston and one 
piston pump), the single pollutant cost effectiveness values were $226 
per ton of methane reduction ($54 with savings) and $814 per ton of VOC 
reduction ($194 with savings). The multipollutant cost effectiveness 
values were $113 per ton of methane reduction ($27 with savings) and 
$407 per ton of VOC reduction ($97 with savings).
    All of these cost effectiveness values for both methane and VOC are 
within the ranges considered reasonable by the EPA, with the exception 
of the single pollutant cost effectiveness values for methane and VOC 
for a piston pump. However, since the multipollutant cost effectiveness 
of both methane and VOC were in the range considered acceptable by the 
EPA for a site with a single piston pump, we determined that this is an 
acceptable option.
    For the transmission and storage segment, the cost effectiveness 
for a single diaphragm pump was $192 per ton of methane removed and 
$40,640 per ton of VOC. On a multipollutant basis, these cost 
effectiveness values were $96 per ton of methane and $20,320 per ton of 
VOC. For a single piston pump, the cost effectiveness was $1,750 per 
ton of methane removed and $26,095 per ton of VOC. On a multipollutant 
basis, these cost effectiveness values were $875 per ton of methane and 
$13,048 per ton of VOC. For the representative site with one diaphragm 
piston and one piston pump, the single pollutant cost effective values 
were $173 per ton of methane reduction and $11,708 per ton of VOC 
reduction, and the multipollutant cost effectiveness values were $87 
per ton of methane reduction and $5,854 per ton of VOC reduction.
    All of the cost effectiveness values for methane on a single 
pollutant basis are within the ranges considered reasonable by the EPA. 
In addition, the multipollutant cost effectiveness for both methane and 
VOC were in the ranges considered reasonable by the EPA for a site with 
one diaphragm and one piston pump.
    In conclusion, because we believe that routing to a process is a 
viable and cost-effective option for pneumatic pumps when it is 
technically infeasible to use a zero-emission pneumatic pump not driven 
by natural gas, this option is included in the proposed NSPS OOOOb. In 
order to utilize this option, an owner or operator must demonstrate 
technical infeasibility. In addition, because the CVS system that 
collects and routes these emissions to a process could develop leaks, 
the proposed NSPS OOOOb requires compliance with the CVS no-detectable 
leaks requirements specified in 40 CFR 60.5411b(a) and (c) of the 
proposed regulatory text.
    The EPA is interested in several aspects related to the option of 
collecting the pneumatic pump emissions and routing them to a process. 
First, we are soliciting information that describes specific situations 
where owners and operators have utilized this option to use, rather 
than lose, the valuable natural gas emitted from pneumatic pumps. We 
are interested in gathering information on the specific processes and 
types of equipment that are needed to do so, as well as information on 
the related costs. We are also interested in information to support our 
understanding that routing to a process achieves a 100 percent 
reduction in emissions. This understanding is based on the fact that 
the gas that is emitted from pneumatic

[[Page 74776]]

pumps is drawn directly from the raw product gas stream that will be 
collected and routed to a gathering and boosting station and eventually 
to a natural gas processing plant (i.e., the gas ``sales line''). 
Therefore, the emissions from the pneumatic pumps are of the same 
composition as the gas in the sales line. Since the emissions are at 
atmospheric pressure, it is likely that the gas would need to be 
compressed prior to re-introduction to the sales line. We do not expect 
that this compression would result in emissions. Similarly, since the 
composition of these emissions is typically high in methane, the heat 
content would make it amendable to being used as fuel, or introduced 
with the primary fuel stream for use in an engine without the need for 
additional processing that could result in emissions.
    This request for information includes information on the 
installation of VRUs. Note that the analysis above did not include the 
installation of a new VRU. As discussed in section IV.D.1.b.iii for 
pneumatic controllers, we do not believe that a VRU would be needed to 
enable the use of the emissions from pneumatic pumps (in contrast to 
emissions from storage vessels and centrifugal compressor wet seal 
fluid degassing systems). Despite this belief, in the analysis for the 
November 2021 proposal, we did analyze the costs to install a new VRU 
to process the emissions from pneumatic pumps to enable the routing to 
a process. We determined that these costs were unreasonable, given the 
emission reductions. One commenter felt that our VRU costs were 
inflated. We are interested in learning about situations where a VRU 
would be needed to enable the use of emissions from a pneumatic pump in 
a process, as well as the costs of those VRUs.\168\ These costs are 
included in the November 2021 TSD.
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    \168\ See Document ID No. EPA-HQ-OAR-2021-0317-0844.
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    We also recognize that there could be situations at sites without 
access to electricity where not only is it technically infeasible to 
utilize zero-emission pneumatic pumps that are not driven by natural 
gas, but it is also technically infeasible to route the emissions to a 
process. Therefore, we also considered the option to route to a control 
device. The analysis conducted for the November 2021 proposal concluded 
that while it was reasonable to route the emissions from a pneumatic 
pump to an existing control device, the cost effectiveness of 
installing a new control device dedicated to the pneumatic pump was 
higher than the EPA considers reasonable. This finding is still valid 
for this proposal for sites with a single pneumatic pump. However, as 
noted above, the EPA changed the pneumatic pump affected facility 
definition for this proposal to be the collection of natural gas 
pneumatic pumps at a site. Therefore, we updated the analysis to 
consider the cost effectiveness of installation of a new control device 
that would control emissions from multiple natural gas-driven pneumatic 
pumps.
    This analysis found that where there are four or more natural gas-
driven pneumatic diaphragm pumps at a site, the cost effectiveness of a 
new combustion device that reduces emissions by 95 percent from all the 
pumps is within the ranges considered reasonable by the EPA. For the 
production segment, the cost effectiveness values for a site with four 
diaphragm pumps are $1,869 per ton of methane reduced and $6,723 per 
ton of VOC reduced on a single pollutant basis. On a multipollutant 
basis, these values are $934 per ton of methane and $3,361 per ton of 
VOC. Therefore, these cost effectiveness values are considered 
reasonable for methane on a single pollutant basis as well as on a 
multipollutant basis. For the transmission and storage segment, the 
single pollutant methane cost effectiveness was $1,430, which is in the 
range considered reasonable by the EPA.
    Therefore, the proposed NSPS OOOOb includes the requirement for 
production and transmission and storage sites as follows: if an owner 
or operator demonstrates that it is technically infeasible to install 
zero-emission non-natural gas-driven pumps, and it is technically 
infeasible to route to a process, the emissions must be routed to a 
control device to achieve 95 percent reduction of the methane and VOC 
if the pneumatic pump affected facility includes four or more diaphragm 
pumps. Note that emissions from all piston pumps at the site would also 
be required to be reduced by 95 percent. For pneumatic pump affected 
facilities with less than four diaphragm pumps, where it has been 
demonstrated that it is technically infeasible to use zero-emission 
non-natural gas-driven pumps and infeasible to route to a process, the 
proposed NSPS OOOOb mirrors the November 2021 proposal. That is, the 
pneumatic pump emissions must be routed to an existing control device 
(if one is available) to achieve 95 percent reduction.
    There are several instances in this hierarchical structure of the 
proposed NSPS OOOOb where less stringent requirements may apply if it 
is determined that the more stringent requirement is technically 
infeasible. The proposed rule requires that these demonstrations be 
made by a qualified professional engineer or an in-house engineer with 
relevant expertise. While several commenters stressed that in-house 
engineers should be allowed to make required certifications and 
determinations, other commenters expressed concerns that only certified 
professional engineers should be allowed to certify technical 
infeasibility. The EPA concluded that the flexibility to allow in-house 
engineers to make these determinations and certifications is warranted, 
especially given the potential shortage of professional engineers with 
specific expertise required for these determinations (that is, 
expertise in solar-powered pneumatic pumps or routing pneumatic pump 
emissions to a process).
    However, the EPA is also committed to ensuring that this technical 
infeasibility provision is not abused or used as a loophole to avoid 
implementing important pollution reduction measures. The EPA stresses 
that each technical infeasibility determination must be documented, and 
the following statement submitted to the EPA (or delegated enforcement 
authority): ``I certify that the assessment of technical infeasibility 
was prepared under my direction or supervision. I further certify that 
the assessment was conducted, and this report was prepared, pursuant to 
the requirements of 40 CFR 60.5393b(c)(1). Based on my professional 
knowledge and experience, and inquiry of personnel involved in the 
assessment, the certification submitted herein is true, accurate, and 
complete.'' The EPA wants to make it clear that in the case that such a 
certification is determined by the Agency to be fraudulent, or 
significantly flawed, not only will the owner or operator of the 
affected facility be in violation of the standards, but the person that 
makes the certification will also be subject to civil and potentially 
criminal penalties.
c. Summary of Proposed NSPS OOOOb
    The proposed NSPS OOOOb defines a pneumatic pump affected facility 
as the collection of natural gas-driven diaphragm and piston pneumatic 
pumps at all types of sites throughout the production, processing, and 
transmission and storage segments of the source category. Specifically, 
these sites include well sites, centralized production facilities, 
onshore natural gas processing plants, and compressor stations. 
Pneumatic pumps that are not driven by natural gas are not included

[[Page 74777]]

in the proposed pneumatic pump affected facility as long as records are 
maintained to verify that non-natural gas-driven pumps are used.
    Natural gas-driven pumps that are in operation less than 90 days 
per calendar year are not part of an affected facility provided that 
the owner or operator keeps records of the days of operation each 
calendar year and submits such records to the EPA (or delegated 
enforcement authority) upon request. Any period of operation during a 
calendar day counts toward the 90-calendar day threshold.
    In addition to the modification definition in 40 CFR 60.14 and the 
reconstruction definition in 40 CFR 60.15, the proposed rule includes 
clarification of these terms for the pneumatic pump affected facility. 
A modification occurs when the number of natural gas-driven pneumatic 
pumps at a site is increased by one or more, and reconstruction occurs 
when either the cost of the pumps being replaced exceeds 50 percent of 
the cost to replace all the pumps, or when 50 percent or more of the 
pneumatic pumps at a site are replaced.
    The proposed BSER is the use of pneumatic pumps not powered by 
natural gas; the proposed standard of performance is zero emissions of 
methane and VOC. As noted above, compliance with this standard 
effectively eliminates the existence of a pneumatic pump affected 
facility (which is a natural gas-driven pump or collection of pumps, by 
definition). For sites in the production or transmission and storage 
segment of the industry who do not have access to electricity, the 
proposed standards include a hierarchical structure that allows the use 
of natural gas-driven pneumatic pumps based on the technical 
feasibility of pneumatic pump control measures. This hierarchy is not 
available to natural gas processing plants, as the only proposed 
requirement is the use of non-natural gas-driven pneumatic pumps at 
these sites.
    If it is demonstrated that it is technically infeasible to utilize 
a pneumatic pump not driven by natural gas at a site in the production 
or transmission and storage segment of the industry which does not have 
access to electricity, compliance may be achieved by collecting methane 
and VOC emissions from all pumps (diaphragm and piston pumps) in the 
affected facility via a CVS and routed to a process, which we 
understand results in 100 percent emissions reductions. The CVS is 
required to comply with the CVS requirements specified in 40 CFR 
60.5411b(a) and (c) of the proposed regulatory text, which includes 
certification by a professional or in-house engineer that the CVS was 
designed properly and was operated in accordance with the no detectable 
emissions provisions. For this ``tier one'' technical infeasibility 
determination, a demonstration must be made that using a solar-powered 
electric pneumatic pump is not technically feasible. This demonstration 
must be certified by either a qualified professional engineer or an in-
house engineer with expertise on the design and operation of solar-
powered pneumatic pumps. Alternatively, this demonstration can be 
certified by a solar-powered pneumatic pump manufacturer that has 
successfully installed solar-powered pneumatic pumps at other oil and 
natural gas sites. In addition, the tier one technical infeasibility 
demonstration must prove that it is not technically feasible to install 
a compressed air system powered by either a natural gas-driven 
generator or a solar-powered generator. This demonstration must 
include, but not be limited to, the ability to operate a generator, 
including access to natural gas; access to solar power; or the 
inability of a compressed air system to power the pneumatic pump. This 
demonstration must be certified by either a qualified professional 
engineer or an in-house engineer with expertise on the design and 
operation of natural gas-driven or solar-powered generators to power 
pneumatic pumps. In addition to the records associated with the 
technical infeasibility determination/certification, a record of the 
certification of the design of the CVS must be maintained, along with 
records of all inspections required to demonstrate compliance with the 
no detectable emissions requirements.
    If it is demonstrated that it is technically infeasible to collect 
the emissions from all pneumatic pumps in the affected facility and 
route them to a process (in addition to the demonstration that it is 
infeasible to utilize a pneumatic pump not driven by natural gas), 
compliance may be achieved by collecting methane and VOC emissions from 
all pumps (diaphragm and piston pumps) in the affected facility via a 
CVS and routing them to a control device that achieves 95 percent 
reduction in methane and VOC emissions. The CVS would be subject to the 
design requirements, specified in 40 CFR 60.5411b(a) and (c) of the 
proposed regulatory text, and must comply with the no detectable 
emissions requirements. The control device would be subject to testing 
and continuous monitoring requirements. This ``tier two'' demonstration 
must include, but is not limited to, safety considerations, distance 
from a process, pressure losses and differentials which impact the 
ability of the process to handle all the pneumatic pump affected 
facility emissions routed to it, or other technical reasons the process 
cannot handle all the pneumatic pump affected facility emissions routed 
to it. This demonstration must be certified by either a qualified 
professional engineer or an in-house engineer with expertise on the 
design and operation of the pneumatic pump affected facility and the 
process to which emissions will be routed. A demonstration of technical 
infeasibility may not be based on the infeasibility of the design and 
operation of CVS to collect emissions from all the pneumatic pumps in 
the affected facility. In addition to the records associated with both 
technical infeasibility determinations and certifications, a record of 
the certification of the design of the CVS must be maintained, along 
with records of all inspections required to demonstrate compliance with 
the no detectable emissions requirements. Records must also be 
maintained of either the performance testing of the control device 
(whether at the site or by the manufacturer), or records demonstrating 
compliance with 40 CFR 60.18 General Provisions flare requirements. 
Finally, monitoring records must be maintained to demonstrate that the 
control device is operating properly on a continuous basis.
    ``Tier three'' of the hierarchy applies if there are less than four 
natural gas-driven diaphragm pumps at a site. In this situation, the 
owner or operator is not required to install a new control device. The 
proposed standard for the pneumatic pump affected facilities at sites 
with less than four diaphragm pumps mirror those proposed in the 
November 2021 proposal, which require that methane and VOC emissions be 
reduced by 95 percent by routing to an existing control device if: (1) 
A control device is onsite, (2) the control device can achieve a 95 
percent reduction, and (3) it is technically feasible to route the 
emissions to the control device. However, the proposed rule would 
exempt an owner or operator from this requirement provided that they 
document the technical infeasibility of routing the emissions to an 
existing control device and submit it in an annual report. Similarly, 
where it is feasible to route the emissions to a control device, but 
the control cannot

[[Page 74778]]

achieve 95 percent reduction, the proposed rule would exempt the owner 
or operator from the 95 percent reduction requirement, provided that 
the owner or operator maintain records demonstrating the percentage 
reduction that the control device is designed to achieve.
    The EPA notes that inherent throughout these proposed pneumatic 
pump requirements are demonstrations of technical infeasibility. Each 
technical infeasibility determination must include a certification, 
signed and dated by the qualified professional engineer or in-house 
engineer. The EPA wants to make it clear that in the case that such a 
certification is determined by the Agency to be fraudulent, or 
significantly flawed, not only will the owner or operator of the 
affected facility be in violation of the standards, but the person that 
makes the certification will also be subject to civil and potentially 
criminal penalties.
2. EG OOOOc
    The proposed presumptive standards for methane emissions from 
existing pneumatic pumps mirror those described above for NSPS OOOOb. 
The EPA did not identify any circumstances that would result in a 
different BSER for existing sources under the EG OOOOc.
    In light of the proposal to require zero-emission pneumatic pumps 
not powered by natural gas for both new and existing sources, the EPA 
would like to highlight comments and solicit related information. 
Commenters on the November 2021 proposal indicated that the proposed 
rules would exacerbate demand, increase costs, and increase pressure on 
the supply chain for zero-emissions systems. One commenter stated that 
reliability and availability of alternate zero-emission options (i.e., 
solar-powered/battery backup systems, and electric, self-contained 
systems) are a major concern for safe and reliable operations.\169\ 
Another commenter indicated that one of their members contacted a 
vendor within the last six months to find out how much deployment there 
has been of solar systems and electric controllers.\170\ The commenter 
reported that the vendor indicated that in the past 10 years, they have 
conducted 200 retrofits and 300 new installs, and the vendor estimates 
that it can only service approximately 200 installs per year. 
Additionally, the commenter indicated that operators are already 
experiencing 6 to 12-month lead times for delivery of solar packages. 
So that it may continue to gather information on this subject, the EPA 
is specifically requesting comment on the availability of pneumatic 
pump systems not powered by natural gas.
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    \169\ See Document ID No. EPA-HQ-OAR-2021-0317-0739.
    \170\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.
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F. Wells and Associated Operations

1. Affected and Designated Facility Definitions
a. NSPS OOOOb
    The November 2021 proposal had three separate affected facilities 
associated with oil and natural gas wells. These included: (1) The well 
completion affected facility, defined as a single well that conducts a 
well completion operation following hydraulic fracturing or 
refracturing; (2) the associated gas affected facility, defined as any 
oil well that produces associated gas; and (3) the well liquids 
unloading affected facility, with two proposed options for the 
definition. Under Option 1, a well liquids unloading affected facility 
was defined as every well that undergoes liquids unloading. Under 
Option 2, a well liquids unloading affected facility was defined as 
every well that undergoes liquids unloading using a method that is not 
designed to completely eliminate venting. Each of these three types of 
affected facilities included proposed definitions of what would 
constitute a modification to an oil and natural gas well. The result of 
including all three definitions would have been that a single well 
could have been three different affected facilities for three different 
emissions sources. In addition, a single well could have been a new 
source affected facility under NSPS OOOOb and a designated facility 
under EG OOOOc.
    To eliminate the potential confusion from this complex regulatory 
structure, the EPA is proposing to change its approach as part of this 
proposed action. Rather than three separate well affected facilities, 
we are now proposing a definition of well affected facility, which is 
defined as a single well, in the proposed NSPS OOOOb. A well is defined 
as a hole drilled for the purpose of producing oil or natural gas. More 
discussion of the rationale for this revision specific to each of the 
three well operations is provided in sections IV.E.2, 3, and 4 below.
    There are separate proposed standards for well completions, 
associated gas from oil wells, and gas well liquids unloading 
operations, all or some of which could apply to a well affected 
facility. These proposed standards and their applicability are 
discussed in more detail in sections IV.E.2, 3, and 4 of this preamble. 
A well affected facility is only required to comply with the standards 
that are applicable to the well. For example, a gas well would not be 
subject to the oil well with associated gas standards. The proposed 
NSPS OOOOb specifies that a modification to an existing well occurs 
when the definition of modification in 40 CFR 60.14 is met, including 
when an existing well undergoes hydraulic fracturing or re-fracturing.
b. EG OOOOc
    The November 2021 proposal only included the oil wells with 
associated gas designated facility, as the proposed definition of 
modification for the NSPS OOOOb well liquids unloading affected 
facility would have resulted in all wells that performed liquids 
unloading being new or modified sources. As discussed above and in 
section IV.E.3, the EPA has not retained the proposed well liquids 
unloading modification definition in this supplemental proposal. 
Therefore, this proposal includes standards for gas well liquids 
unloading at designated facilities in the proposed EG OOOOc. However, 
since the fracturing or re-fracturing of an existing well would 
constitute a modification under NSPS OOOOb, which makes the well a well 
affected facility under NSPS OOOOb, there would never be an existing 
well subject to completion requirements.
    The well designated facility definition in EG OOOOc is now proposed 
to be defined as a single well and EG OOOOc would include presumptive 
standards for associated gas from oil wells and gas well liquids 
unloading.
2. Associated Gas From Oil Wells
a. NSPS OOOOb
i. November 2021 Proposal
    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. In the November 2021 proposal, the EPA proposed standards 
in NSPS OOOOb to reduce methane and VOC emissions resulting from the 
venting of associated gas from oil wells. Specifically, the November 
2021 proposal would have required owners and operators of oil wells to 
route associated gas to a sales line. If access to a sales line was not 
available, the EPA proposed that the gas could have been used as an 
onsite fuel source, used for another useful purpose that a purchased 
fuel or raw material would serve, or routed to a flare or other control 
device that achieves at least 95 percent reduction of methane and VOC

[[Page 74779]]

emissions.\171\ The EPA also requested comment on whether to include 
re-injecting associated gas for enhanced oil recovery or another 
purpose should be included in the list of beneficial uses. The 
following sections provide discussions of the comments submitted on the 
November 2021 proposal, the changes resulting from these comments, and 
our rationale for the changes. Section IV.E.2.iii summarizes the 
resulting proposed requirements included in this supplemental proposal.
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    \171\ The EPA solicited comment on whether to also include re-
injecting associated gas as an alternative (86 FR 63237; November 
15, 2021) and based on comments in support of this option [EPA-HQ-
OAR-2021-0317-0844], is including such alternative in this 
supplemental proposal.
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ii. Changes From November 2021 Proposal
    The BSER determination for associated gas from oil wells was 
discussed in section XII.J.1.e of the November 2021 proposal (86 FR 
63237-63238; November 15, 2021). The EPA did not receive any comments 
on the proposal that resulted in a change to the analysis that had 
concluded that BSER for associated gas from oil wells was the routing 
of the associated gas to a sales line.
    In this action, we are proposing changes to the associated gas from 
the oil wells affected facility definition, the hierarchy of the 
standard, and the compliance options. In addition to proposed changes 
associated with these topics, a significant addition to the proposed 
rule is the establishment of requirements for situations when 
associated gas from an oil well that is primarily either routed to a 
sales line or used for another beneficial purpose is unable to utilize 
the gas in that manner due to gathering system or other disruptions. In 
addition, the EPA is soliciting additional information on potential 
emerging technologies that provide uses for the associated gas in a 
beneficial manner other than routing to a sales line, using as a fuel, 
or reinjecting the gas. Examples of such emerging technologies provided 
by commenters include methane pyrolysis \172\ and condensing the gas 
and transporting it to other sites for use.\173\
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    \172\ See Document ID No. EPA-HQ-OAR-2021-0317-0594.
    \173\ See Document ID No. EPA-HQ-OAR-2021-0317-0558.
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    Hierarchy of the Standard and Control Options. As discussed in 
section IV.E.1.b.i, the standard for associated gas from oil wells in 
the November 2021 proposal was to route the associated gas to a sales 
line. If access to a sales line was not available, the proposal allowed 
the gas to be used as an onsite fuel source, used for another useful 
purpose that a purchased fuel or raw material would serve, or routed to 
a flare or other control device that achieves at least 95 percent 
reduction in methane and VOC emissions.
    The EPA specifically solicited comment on how ``access to a sales 
line'' should be defined. Several commenters \174\ stated that access 
to a sales pipeline is based on numerous criteria that can be outside a 
well operator's control. They indicated that, in most cases, the 
midstream company that designs, builds, and operates the gas gathering 
system (sales line) and gas processing plant is not the same as the 
well owner and operator, landowner, and mineral lease owner. Thus, 
commenters concluded that ``access to a sales line'' does not equate to 
availability to route gas into that sales line.
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    \174\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0793, EPA-HQ-
OAR-2021-0317-0808, EPA-HQ-OAR-2021-0317-0911.
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    Commenters also objected to the overall construct of the proposal 
where the standard required the routing to a sales line in situations 
where access to sales line was available. They indicated that using the 
gas as an onsite fuel source should be an option that was allowed on an 
equal basis with routing to a sales line.
    The EPA agrees with these commenters regarding the associated gas 
from oil wells standards. First, the EPA understands that the sales 
line is typically not under the control of the well owner, and that the 
gathering system owner dictates when gas can be routed to a sales line. 
We believe this understanding supports allowing other uses of 
associated gas, which also avoid methane and VOC emissions from venting 
or flaring of associated gas, as acceptable compliance options. 
Specifically, while BSER was determined to be routing to a sales line, 
we agree that beneficial uses of the associated gas should be allowed 
as these options are equivalent in terms of emission reduction to the 
identified BSER. Therefore, we are proposing to expand what is 
considered beneficial use to include options beyond routing to the 
sales line. This proposed rule would require any of the following 
options for beneficial use: (1) Routing associated gas from oil wells 
to a sales line; (2) using the associated gas as a fuel or for another 
useful purpose that a purchased fuel or raw material would serve; (3) 
or reinjecting the associated gas into the well or injecting the 
associated into another well for enhanced oil recovery. Regarding re-
injection, commenters indicated that re-injection should be included as 
one of the options allowed. One commenter stated that well operators 
may prefer to reinject associated gas. They pointed out that 
reinjection is used widely in Alaska, where 90 percent of associated 
gas is injected into oil-bearing formations. They concluded that 
reinjection as a method of gas capture has significant emissions 
reduction benefits, because it largely eliminates emissions of methane 
and other pollutants.\175\
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    \175\ See Document ID No. EPA-HQ-OAR-2021-0317-0844.
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    As noted above, commenters also mentioned examples of emerging 
techniques that provide additional beneficial uses of the associated 
gas, including compressing the gas and transporting it to a nearby 
processing plant or pipeline and methane pyrolysis. The EPA interprets 
the third criterion, ``used for another useful purpose,'' to include 
these emerging techniques but is soliciting comment whether an 
additional criterion should be added to make this clear. The EPA is 
also soliciting comment on more specific technologies that have been 
proven to be viable in the field to utilize associated gas and avoid 
venting or flaring.
    Some commenters stated that the proposed rule would not succeed in 
ensuring that oil and gas operators will not flare associated gas in 
situations where other options were available, and these commenters 
opposed routine flaring as a compliance alternative on par with the 
non-sales line ``beneficial'' use options. They urged the EPA to 
abandon what they described as an ``unworkable framing,'' and instead 
suggested that the EPA adopt a BSER that would eliminate routine 
flaring except in specific and narrowly defined circumstances. We agree 
that flaring of the gas should only be allowed in situations where it 
is not feasible to route the associated gas to a sales line or use it 
for one of the other useful purposes described above. Therefore, this 
proposed rule would allow flaring of the associated gas only if the 
owner or operator certifies that it is not feasible to route the 
associated gas to a sales line or use it for another beneficial purpose 
due to technical or safety reasons. This demonstration would need to 
address the specifics regarding the lack of availability to a sales 
line, including efforts by operators to get access to a sales line or 
to facilitate alternative off-site transport and use of associated gas. 
The demonstration would also need to demonstrate why all potential 
beneficial

[[Page 74780]]

uses (including emerging techniques) are not feasible due to technical 
or safety reasons. The first demonstration would require certification 
by a professional engineer or other qualified individual and would be 
submitted in the first annual report for the well affected facility. In 
each subsequent annual report, the owner or operator would be required 
to report whether any circumstances had changed regarding the need to 
flare relative to the initial certification, and if so, which 
beneficial use would be applied to the associated gas.
    The EPA recognizes that several states have adopted standards to 
further reduce routine flaring of associated gas, including Colorado 
and New Mexico. As noted above, several commenters also urged the EPA 
to take additional steps to eliminate routine flaring of associated 
gas, except in very limited cases such as emergencies or for safety 
reasons. Therefore, the EPA is taking comment on steps the Agency 
should consider taking to disallow the indefinite continuation of 
routine flaring. First, the EPA is taking comment on whether the 
ongoing annual requirement to report whether circumstances had changed 
regarding the need to flare should result in a need to perform a more 
thorough analysis and engineering certification comparable to the 
initial certification required once an owner or operator becomes 
subject to the rule. For example, it may be appropriate to require an 
owner or operator to provide an additional engineering certification 
that flaring is the only option where a new gathering pipeline is 
installed within a certain distance of an oil well. Second, the EPA is 
taking comment on whether it would be appropriate to require more 
rigorous consideration of alternatives to flaring after a set threshold 
is reached (e.g., after a set time of flaring (such as 2 years) or 
after a set volume of gas has been flared). Third, the EPA requests 
comment on whether there are any provisions in existing state 
regulations beyond what is already included in this supplemental 
proposal, or other measures (such as minimum capture requirements or 
volumetric limits on flaring), that the EPA should consider in its BSER 
analysis. Finally, the EPA is also soliciting comment on whether there 
are specific emerging technologies that should be required to be 
addressed in this demonstration and listed in the rule.
    Requirements when Gathering System or Other Disruption Occurs. The 
EPA is aware that when associated gas is typically routed to a sales 
line there could be situations that arise that can cause an 
interruption of the ability to route the gas to the sales line. As 
discussed above and pointed out by commenters, this situation is 
usually not under the control of the owner or operator of the well. The 
EPA agrees that interruptions where the gathering system owner is 
suddenly unable to accept the associated gas from the well could also 
occur that impact the ability to utilize the associated gas as a fuel 
or for another useful purpose. The EPA has considered options for this 
situation for this supplemental proposal. One option considered was 
that this situation would constitute a deviation or violation of the 
standard unless the owner or operator elected to shut the well in and 
halt the production of the associated gas. The EPA did not select this 
option in this supplemental proposal. The EPA concluded that such 
situations could constitute a technical or safety reason that could be 
used to justify the use of a control device that achieves 95 percent 
reduction of methane and VOC emissions. Therefore, the EPA is proposing 
to require that if owners and operators anticipate that there may be 
interruptions in the ability to route the associated gas to a sales 
line or to use it for another beneficial purpose, they must provide a 
technical or safety demonstration in their annual report and install 
and operate a control device that achieves the required reduction 
during these temporary periods. It is anticipated this control device 
would need to be permanently installed to account for these periods 
when associated gas could not be routed to a sales line or used for 
other beneficial purposes, but the EPA is soliciting comment on whether 
the use of temporary controls could also serve this purpose. Further 
the EPA is soliciting comment on what additional requirements would be 
necessary to ensure a temporary control device is onsite and 
operational to immediately control emissions when necessary for these 
circumstances. Venting of the associated gas under any circumstances 
would represent a violation of the proposed standards, even if for a 
short period.
    Potential Exemptions and Alternative BSER for Unique Circumstances. 
Several commenters on the November 2021 proposal identified situations 
where it would not only be infeasible to route the associated gas to a 
sales line or use it for another beneficial purpose, but where it would 
also be infeasible to route it to a flare or other control device to 
achieve 95 percent reduction in methane and VOC emissions. Examples of 
these situations include when the flow rate, pressure, or volume of the 
associated gas is insufficient to route to a sales line or to support 
the continuous operation of a flare or combustion device; when the 
composition of the gas is such that it cannot be routed to a sales line 
or used in some manner (e.g., 97 percent CO2 and 3 percent 
methane) and it does not contain sufficient heat content to combust 
without the addition of unreasonable amounts of propane; wildcat wells; 
and delineation wells. One commenter provided detailed information 
about the issues with certain wells in Wyoming,\176\ The EPA believes 
that these situations could warrant an exemption or an alternative 
standard. However, this proposed rule does not include any exemptions 
or allowances for these situations due to lack of specific sufficient 
information. Therefore, the EPA is interested in additional information 
on gas compositions of associated gas that would make it both unusable 
for a beneficial purpose and unable to be flared. The EPA is not only 
interested in why commenters feel these situations warrant an exemption 
from the associated gas standards as proposed, but also what methods 
are currently in use, or could be used, to minimize methane and VOC 
emissions in these situations.
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    \176\ See Document ID No. EPA-HQ-OAR-2021-0317-0955.
---------------------------------------------------------------------------

iii. Summary of Proposed Standards
    In summary, this supplemental proposal allows owners and operators 
four compliance options to reduce or eliminate emissions of methane and 
VOC from associated gas from oil wells. These options are: (1) Recover 
the associated gas from the separator and route the recovered gas into 
a gas gathering flow line or collection system to a sales line, (2) 
recover the associated gas from the separator and use the recovered gas 
as an onsite fuel source, (3) recover the associated gas from the 
separator and use the recovered gas for another useful purpose that a 
purchased fuel or raw material would serve, or (4) recover the 
associated gas from the separator and reinject the recovered gas into 
the well or inject the recovered gas into another well for enhanced oil 
recovery.
    Associated gas cannot be routed to a flare or other combustion 
device unless the owner or operator demonstrates that all four options 
discussed above are infeasible due to technical or safety reasons, and 
that demonstration is approved by a certified professional engineer. 
Any combustion device must meet the requirements in 40 CFR

[[Page 74781]]

60.5412b and that monitoring, recordkeeping, and reporting be conducted 
to ensure that the combustion device is constantly achieving the 
required 95 percent reduction. More information on the control device 
monitoring and compliance provisions is provided in section IV.H of 
this preamble.
    In each annual report, owners and operators would be required to 
identify each well affected facility with associated gas that was 
constructed, modified, or reconstructed during the reporting period. 
The report would specify whether the associated gas will be routed into 
a gas gathering flow line or collection system to a sales line, used as 
an onsite fuel source, used for another useful purpose that a purchased 
fuel or raw material would serve, reinjected into the well, or injected 
into another well for enhanced oil recovery. If making a demonstration 
that it is infeasible to utilize one of these options due to technical 
or safety reasons, this demonstration would also be included in the 
first annual report. This demonstration would clearly and 
comprehensively justify why all of these options are infeasible, 
including all emerging technologies that could represent a beneficial 
use of the gas. This demonstration would be required in situations 
where the associated gas is always routed to a control device, as well 
as for situations where disruptions or interruptions result in the need 
to route the associated gas to a control device for temporary periods.
    In subsequent annual reports, owners and operators complying by 
routing the associated gas to a gas gathering flow line or collection 
system to a sales line, used as an onsite fuel source, used for another 
useful purpose that a purchased fuel or raw material would serve, 
reinjected into the well, or injected into another well for enhanced 
oil recovery would be required to report all instances when associated 
gas was vented to the atmosphere. Owners and operators complying by 
routing the associated gas to a control device and achieving 95 percent 
reduction in methane and VOC would be required to report all instances 
when associated gas was vented to the atmosphere. In addition, these 
owners and operators would be required to report any changes made at 
the site since the original technical infeasibility demonstration and 
whether the change impacted the feasibility to route the associated gas 
to a gas gathering flow line or collection system to a sales line, use 
the gas as an onsite fuel source, use the gas for another useful 
purpose that a purchased fuel or raw material would serve, reinject the 
gas into the well, or inject the gas into another well for enhanced oil 
recovery. If the change did not impact this feasibility, a revised 
demonstration and certification would be required. If the change did 
impact the feasibility, the owner or operator would need to report the 
new method of compliance that is utilized.
    Required records would include documentation of the specific type 
of compliance method (i.e., routed into a gas gathering flow line or 
collection system to a sales line, used as an onsite fuel source, used 
for another useful purpose that a purchased fuel or raw material would 
serve, injected into another well for enhanced oil recovery) was used. 
Owners and operators would also be required to maintain records that 
demonstrate why the required capture and use requirements are not 
feasible and why the use of a control device is the only option. If the 
control device is only used on a temporary basis when disruptions or 
interruptions occur in the primary compliance method for the associated 
gas, the owner or operator would document the periods that the gas is 
routed to the control device. All records associated that demonstrate 
proper design and operation of the control device would also be 
required to be maintained (see section IV.G of this preamble). Finally, 
all instances where emissions are vented would be recorded, along with 
records of actions that were taken during these periods to minimize 
emissions to the atmosphere.
b. EG OOOOc
    The proposed presumptive standards for associated gas from existing 
oil wells mirror those described above for NSPS OOOOb. The EPA did not 
identify any circumstances that would result in a different BSER for 
existing sources under the EG OOOOc.
3. Gas Well Liquids Unloading Operations
a. NSPS OOOOb
i. November 2021 Proposal
    In the November 2021 proposal, the EPA proposed to add standards to 
reduce VOC and methane emissions from each new, modified, or 
reconstructed gas well that conducts a well liquids unloading operation 
in NSPS OOOOb. In that proposal, the EPA proposed a standard that would 
require owners or operators to perform well liquids unloading with zero 
methane or VOC emissions. In the event that it is technically 
infeasible or not safe to perform well liquids unloading with zero 
emissions, the EPA proposed to require owners and operators to 
establish and employ BMPs to minimize methane and VOC emissions during 
well liquids unloading operations to the extent possible. Two 
regulatory approaches were co-proposed in the November 2021 proposal. 
The first approach defined the affected facility as every well that 
undergoes liquids unloading, while the second approach defined the 
affected facility as every well that undergoes liquids unloading using 
a method that is not designed to completely eliminate venting. Both 
approaches require zero emissions unless technically infeasible, and 
where infeasible, both approaches require minimizing venting using 
BMPs.
ii. Changes From November 2021 Proposal
    As described in section IV.E.1, the EPA is proposing to define the 
``affected facility'' as a single well in this supplemental proposal, 
instead of defining it as a well that undergoes liquids unloading. 
Further, the EPA is revising the ``modification'' definition to apply 
to a single well that undergoes hydraulic fracturing or refracturing. 
This revised definition replaces the definition proposed in the 
November 2021 proposal, where all well liquids unloading events would 
have been considered a modification.
    Several commenters stated that the November 2021 proposal's 
definition of modification for well liquids unloading operations was 
flawed in a number of respects. First, commenters asserted that not all 
well liquids unloading operations result in an increase in emissions to 
the atmosphere because some operations do not vent gas and therefore 
have zero emissions. We agree with commenters on this point; therefore, 
we are not maintaining the proposed definition that every well liquids 
unloading operation is a modification. Second, commenters stated that 
well liquids unloading operations are a part of the normal operation of 
the well and do not result in a physical or operational change to the 
well, and therefore do not meet the definition of modification in 40 
CFR 60.2. The EPA agrees with the commenters that well liquids 
unloading operations are not physical changes to the well itself. A 
well liquids unloading operation does not change the shape, size, or 
any other physical feature of the well (i.e., the hole drilled for the 
purpose of producing oil or natural gas).
    The question of whether well liquids unloading operations 
constitutes an operational change to the well is more nuanced. The EPA 
understands that every gas well will eventually need to have liquids 
removed in order to improve or maintain production. While

[[Page 74782]]

the definition of modification in this proposal has been adjusted to 
reflect the information commenters have provided, the EPA has yet to 
reach a conclusion on whether certain types of liquids unloading events 
could be an operational change to a well. The EPA is therefore 
requesting comment on operational scenarios where a well liquids 
unloading event could constitute a modification. Operational scenarios 
that may be considered a modification regarding well liquids unloading 
could include: (1) The first time, in the life of the well, that well 
liquids unloading occurs, (2) the first time, after fracturing or 
refracturing a well, that well liquids unloading occurs, (3) a change 
in the type or method of well liquids unloading, or (4) ongoing liquids 
unloading as part of a regular operational schedule. The EPA is 
requesting specific comment on whether these operational scenarios, or 
any additional ones, may or may not constitute a modification.
iii. Summary of Proposed Requirements
    In this supplemental proposal, the EPA has provided regulatory text 
similar to the November 2021 co-proposed option 1, where all gas well 
liquids unloading operations would be subject to the regulatory 
requirements. The EPA is proposing the same standard of performance as 
discussed in the November 2021 proposal: perform well liquids unloading 
with zero methane or VOC emissions. The BSER is to employ techniques or 
technologies that eliminate methane and VOC emissions. Where it is 
technically infeasible or not safe to meet the zero emissions standard, 
employ BMPs to minimize methane and VOC emissions during well liquids 
unloading operations to the maximum extent possible. While we received 
multiple comments recommending regulating only well liquids unloading 
events that result in vented emissions, we are not including proposed 
regulatory text for the co-proposed option 2. Should the EPA decide to 
finalize the standards as stated in the November 2021 co-proposed 
option 2, the regulatory text specific to BMPs would remain relevant 
and is already provided in this supplemental proposal. As stated above, 
there are malfunctions that can result in vented emissions from well 
liquids unloading operations that would otherwise meet the zero 
emissions standard. Further, since each well liquids unloading 
operation is conducted based on the site-specific circumstances at the 
time the operation is planned, the EPA is concerned that a well might 
fluctuate between falling within and out of the scope of the standards 
if the standards only applied to well liquids unloading operations that 
result in vented emissions. Therefore, for ease of implementation to 
the owner or operator, the EPA is proposing to apply the proposed 
standards to all well liquids unloading operations regardless of if the 
operation results in vented emissions. The EPA is, however, 
specifically requesting further comment and any additional information 
regarding co-proposed option 2, where standards only apply to wells 
with well liquids unloading operations that result in vented emissions.
    The EPA is also proposing specific recordkeeping and reporting 
requirements related to well liquids unloading operations. Wells that 
utilize a non-venting method would have reporting and recordkeeping 
requirements that would include records of the number of well liquids 
unloading operations that occur within the reporting period and the 
method(s) used for each well liquids unloading operation. A summary of 
this information would also 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 this proposed rule, 
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.
    Additionally, for wells that utilize methods that vent to the 
atmosphere, the proposed rule would require: (1) Documentation 
explaining why it is infeasible to utilize a non-venting method due to 
technical, safety, or economic reasons; (2) development of BMPs that 
ensure that emissions during liquids unloading are minimized; (3) 
employment of the BMPs during each well liquids unloading operation and 
maintenance of records demonstrating that the BMPs were followed; (4) 
reporting in the annual report both the number of well liquids 
unloading operations and any instances where the well liquids unloading 
operations did not follow the BMPs.
b. EG OOOOc
    Since the November 2021 proposal considered all well liquids 
unloading events to be a modification, the EPA did not propose a 
designated facility definition or presumptive standards for well 
liquids unloading in the EG OOOOc. With the revisions to the affected 
facility definition and what activities constitute a modification, the 
EPA is now proposing to define a designated facility as a single well, 
like in the revised proposal for NSPS OOOOb. Further, the EPA is 
proposing presumptive standards for existing wells that conduct well 
liquids unloading operations in EG OOOOc that are the same as the 
standards proposed in NSPS OOOOb. Because the proposed standards 
provide flexibility for owners and operators to make site-specific 
decisions about what well liquids unloading operations to employ, the 
EPA did not identify any circumstances that would result in a different 
BSER for existing sources under EG OOOOc.
4. Well Completions
a. NSPS OOOOb
    The EPA proposed to retain the requirements found in NSPS OOOO and 
NSPS OOOOa for reducing methane and VOC emissions through reduced 
emission completion (REC) and completion combustion in the November 
2021 proposal. These standards would apply to well completions of 
hydraulically fractured or refractured oil and natural gas wells. The 
EPA is not proposing changes to the standards in this supplemental 
proposal, and the proposed regulatory text at 40 CFR 60.5375b reflects 
the standards of performance as proposed in the November 2021 proposal.
    The proposed regulatory text included in this supplemental proposal 
is similar to the regulatory text found in 40 CFR 60.5375a for NSPS 
OOOOa. While the regulatory text is similar, the EPA has been made 
aware of potential confusion related to the well completion 
requirements and well completion recordkeeping requirements for wildcat 
wells, delineation wells, and low-pressure wells. Therefore, the 
proposed regulatory text for NSPS OOOOb includes language to clarify 
these particular standards for new, modified, and reconstructed sources 
moving forward. First, the EPA is proposing regulatory text at 40 CFR 
60.5375b(f) to clearly state the requirement to route emissions from 
wildcat well, delineation well, and low-pressure well completions to a 
completion combustion device in any instance (unless combustion creates 
a fire or safety hazard or can damage tundra, permafrost or waterways). 
The EPA is aware from implementation of NSPS OOOOa that owners and 
operators are unclear if they can choose to comply with 40 CFR 
60.5375a(f)(3)(ii) and make

[[Page 74783]]

a claim of technical infeasibility for the separator to function, which 
then precludes the requirement to route recovered emissions to a 
completion combustion device. This was not the EPA's intent in NSPS 
OOOOa and for this reason, we are proposing to clearly specify at 40 
CFR 60.5375b(f) that an alternative to route to a separator (instead of 
routing all flowback to a completion combustion device) is available 
only when the owner or operator is able to operate a separator and has 
the separator onsite (or otherwise available for use) and ready for use 
to comply with the alternative during the entirety of the flowback 
period.
    Second, the EPA is proposing to eliminate recordkeeping 
requirements which are not necessary for wildcat wells, delineation 
wells, and low-pressure wells that had previously been included in NSPS 
OOOOa. Specifically, the EPA is proposing to not require records for 
``beneficial'' use of recovered gas (i.e., routed to the gas flow line 
or collection system, re-injected into the well or another well, used 
as an onsite fuel source, or used for another useful purpose that a 
purchased fuel or raw material would serve) nor records of ``specific 
reasons for venting in lieu of capture.'' These records are not 
required for wildcat wells, delineation wells, and low-pressure wells 
because the well completion standards at 40 CFR 60.5375b(f) require 
that all flowback, or gas recovered from flowback through the operation 
of a separator, be routed to a completion combustion device (i.e., 
there will not be an instance, when complying with 40 CFR 60.5375b(f), 
that beneficial use of recovered gas will occur).

G. Centrifugal Compressors

    As discussed in section XII.F of the November 2021 proposal 
preamble (86 FR 63220; November 15, 2021), centrifugal compressors are 
used throughout the natural gas industry to move natural gas along the 
pipeline. These compressors are a significant source of methane and VOC 
emissions. Centrifugal compressors are powered by turbines, which 
utilize a small portion of the natural gas being compressed to fuel the 
turbine. As an alternative to natural gas-fueled turbines, some 
centrifugal compressors use an electric motor.
    Centrifugal compressors require seals around the rotating shaft to 
minimize gas leakage from the point at which the shaft exits the 
compressor casing. There are two types of seal systems: wet seal 
systems and mechanical dry seal systems.
    Wet seal systems use oil, which is circulated under high pressure 
between three or more rings around the compressor shaft, forming a 
barrier to minimize compressed gas leakage. Very little gas escapes 
through the oil barrier, but considerable gas is absorbed by the oil. 
The amount of gas absorbed and entrained by the oil barrier is affected 
by the operating pressure of the gas being handled; higher operating 
pressures result in higher absorption of gas into the oil. Seal oil is 
purged of the absorbed and entrained gas (using heaters, flash tanks 
and degassing techniques) and recirculated to the seal area for reuse. 
Gas that is purged from the seal oil is commonly vented to the 
atmosphere.
    Dry seal systems do not use any circulating seal oil. Dry seals 
operate mechanically under the opposing force created by hydrodynamic 
grooves and springs. Emissions occur from dry seals around the 
compressor shaft vent.
1. NSPS OOOOb
a. November 2021 Proposal
i. Affected Facility
    The November 2021 proposal defined the centrifugal compressor 
affected facility as a single centrifugal compressor using wet seals 
(including centrifugal compressors using wet seals located at 
centralized production facilities). The November 2021 proposal excluded 
centrifugal compressors using wet seals located at a standalone well 
site from the affected facility definition under NSPS OOOOb.
ii. Summary of Proposed BSER Analysis
    November 2021 Proposal BSER Analysis. The BSER analysis methodology 
presented in the November 2021 proposal (86 FR 63221; November 15, 
2021) was consistent with what was used to support the 2011 NSPS OOOO 
and 2016 NSPS OOOOa BSER analyses. The EPA conducted emissions 
reduction cost effectiveness analyses for various control options using 
both the single pollutant and multipollutant approaches.\177\
---------------------------------------------------------------------------

    \177\ See section III.E of this preamble and 86 FR 63154 
(November 15, 2021).
---------------------------------------------------------------------------

    The EPA used emissions factors for uncontrolled methane emissions 
from wet seals in the November 2021 proposal analysis that were based 
on the baseline uncontrolled methane emissions factors used for the 
2016 NSPS OOOOa analysis, in addition to the capital costs for flares 
and associated equipment (e.g., CVS) necessary to route emissions to 
the flare (with costs updated to 2016 dollars). These baseline 
estimates of uncontrolled emissions were higher than the emissions the 
EPA estimated for these sources in both the 2015-2020 GHGRP subpart W 
and 2019 GHGI for all industry segments, with the exception of the 
GHGRP subpart W onshore production and gathering and boosting segments. 
The reduction in emissions attributed to centrifugal compressors in the 
2019 GHGRP subpart W and 2019 GHGI is likely due to the increased 
deployment of emissions controls resulting from the 2012 NSPS OOOO and 
2016 NSPS OOOOa, as well as a shift from the use of wet seals to dry 
seals by the industry since these rules were promulgated.
    Various control options were evaluated as part of the November 2021 
proposal to reduce emissions from centrifugal compressors. Such options 
included control techniques that limit emissions across the rotating 
shaft of the wet seal centrifugal compressor and techniques to capture 
and control emissions using a combustion device or by routing to a 
process. Based on cost analyses conducted, the November 2021 proposal 
for both the NSPS OOOOb and EG OOOOc rules required that VOC and/or 
methane emissions from each centrifugal compressor wet seal fluid 
degassing system be reduced by 95 percent by routing emissions to a 
control device or to a process.
    The November 2021 proposal solicited specific comment on emissions 
from wet seal compressors, as well as information on lower-emitting wet 
seal compressor designs. See 86 FR 63221 (November 15, 2021). The EPA 
also solicited comments on dry seal compressor emissions, seeking 
information on 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, and mechanical 
failure) have the potential to impact methane and VOC emissions. The 
EPA further requested information on whether owners and operators of 
dry seal compressors currently implement standard operating procedures 
in order to identify and correct operational or malfunctioning 
conditions that have the potential to increase emissions from dry seal 
systems. Finally, the EPA also requested information on whether it 
should consider evaluating BSER and developing NSPS standards for dry 
seal compressors.
b. Changes to Proposal and Rationale
    The EPA is proposing changes and clarifications to the November 
2021 proposed standards for NSPS OOOOb. Specifically, we are proposing 
to: (1)

[[Page 74784]]

Revise the affected facility definition to include all centrifugal 
compressors (i.e., both wet seal and dry seal configurations), (2) 
specify that self-contained wet seal centrifugal compressors meet the 
NSPS OOOOb BSER requirements, and (3) set numerical emission limit 
requirements for dry seal and self-contained wet seal centrifugal 
compressors.
i. Wet Seal Centrifugal Compressors
    The EPA received comments that included specific data on the 
November 2021 proposal related to emissions, costs, and the proposed 
standards/analyses for wet seal centrifugal compressors.\178\ These 
commenters asserted that actual wet seal centrifugal compressor 
baseline emissions are significantly lower than the emissions estimates 
that the EPA used in the November 2021 proposal's BSER analysis and 
recommended that the EPA use updated emissions information reported 
under GHGRP subpart W. One of the commenters provided information on 
wet seal centrifugal compressor emissions for their sources in the 
transmission segment and requested the EPA consider using it in any new 
BSER analysis.\179\ This commenter also opined that the proposed 95 
percent reduction standard is unclear insofar as there is no indication 
of what value the reduction is to be measured against. This commenter 
stated that for seals that emit de minimis levels of VOC or methane, it 
would be impracticable to further reduce such emissions and that 
assuming emissions can be calculated, the proposed BSER of routing 
emissions to a control device or to a process would be cost 
prohibitive.
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    \178\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0415 and EPA-HQ-
OAR-2021-0317-1375.
    \179\ See Document ID No. EPA-HQ-OAR-2021-0317-1375.
---------------------------------------------------------------------------

    These same commenters also stated that the costs used by the EPA in 
the November 2021 proposal's BSER analyses were not representative of 
actual costs, and that the EPA had underestimated the costs for the 
control options evaluated. One of the commenters provided detailed cost 
information that they stated was more representative of actual costs 
for three combustion scenarios, the option to route to a process for 
control, and retrofit costs.
    Finally, these same commenters suggested that the EPA consider a de 
minimis exemption, such as an exemption for limited use wet seal 
centrifugal compressors or the establishment of an emissions 
applicability threshold (referring to California's centrifugal 
compressor requirements as an example) \180\ where a wet seal 
compressor that has a measured flow rate less than a specified 
threshold would be exempt from regulatory requirements.
---------------------------------------------------------------------------

    \180\ California's Regulation for Greenhouse Gas Emission 
Standards for Crude Oil and Natural Gas Facilities rule (California 
Code of Regulations, Title 17, Division 3, Chapter 1, Subchapter 10 
Climate Change, Article 4, Subarticle 13, Section 95668(d)(4-9)).
---------------------------------------------------------------------------

    The EPA re-evaluated the November 2021 BSER in light of the 
suggestions from commenters related to emissions and costs. We used 
GHGRP subpart W emissions information because the GHGRP requires a 
multi-step data verification process, which increases the confidence in 
the reliability of data and resulting analyses.\181\ The methodology we 
used for estimating emissions from compressors is consistent with the 
methodology used for the November 2021 proposal. See 86 FR 63220 
(November 15, 2021). The wet seal centrifugal compressor GHGRP subpart 
W methane uncontrolled emissions/emissions factors are based on 
volumetric emissions, which were converted to a mass emission rate for 
this analysis. The resulting baseline uncontrolled emissions per wet 
seal centrifugal compressor are 251 tpy methane (69.9 tpy VOC) from wet 
seal compressors at gathering and boosting sites, 163 tpy methane (45.4 
tpy VOC) from wet seal compressors at natural gas processing plants, 
and 66 tpy methane (1.8 tpy VOC) from wet seal compressors at 
transmission and storage facilities. These baseline uncontrolled 
emissions per wet seal centrifugal compressor are higher than what we 
used in the November 2021 proposal analysis for the gathering and 
boosting segment (based on GHGRP subpart W emissions factor), but lower 
for all other segments of the industry.\182\
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    \181\ EPA (2020) Greenhouse Gas Reporting Program. U.S. 
Environmental Protection Agency. Data reported as of August 7, 2021.
    \182\ U.S. Environmental Protection Agency. Supplemental 
Background Technical Support Document for the Proposed New Source 
Performance Standards (NSPS) and Emissions Guidelines (EG). August 
2022.
---------------------------------------------------------------------------

    The same control options from the analysis for the November 2021 
proposal (routing to a control device and routing to a process) were 
evaluated with the above updates. Additionally, we evaluated a new 
option to address dry seal centrifugal compressor emissions, as 
discussed in more detail later in this section.
    Routing to a control device. As discussed in the November 2021 
proposal, a combustion device generally achieves 95 percent reduction 
of methane and VOC when operated according to the manufacturer 
instructions. Therefore, 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. 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 operating costs for the 
installation of a combustion device used in the updated analysis 
presented with this supplemental proposal are based on information 
obtained from commenters regarding a new high-end enclosed 
combustor.\183\ These costs were adjusted from 2021 dollars to 2019 
dollars for consistency with the other analyses in this rulemaking. The 
updated capital costs of $123,559 were annualized at 7 percent based on 
an equipment life of 10 years. The total annualized capital costs were 
estimated to be $17,592. The annual operating costs used are based, in 
part, on costs assumed in the 2011 NSPS OOOO TSD and 2016 NSPS OOOOa 
TSD,\184\ with the costs again updated to reflect 2019 dollars. The 
resulting annual operating costs (including annual administrative, 
taxes, and insurance costs) were estimated to be $105,472. Therefore, 
the updated estimated total annual costs (including annualized capital 
and operating costs) are $123,063 per compressor. There are no cost 
savings estimated for this option because the recovered natural gas is 
combusted.
---------------------------------------------------------------------------

    \183\ See Document ID No. EPA-HQ-OAR-2021-0317-1375.
    \184\ See Document ID Nos. EPA-HQ-OAR-2010-0505-0045 and EPA-HQ-
OAR-2010-0505-7631.
---------------------------------------------------------------------------

    As a result of the analysis and cost-effectiveness shown in Table 
32 below, the EPA has determined that the costs of routing the captured 
gas from the centrifugal compressor wet seal degassing system to a 
control device are reasonable for the control of methane for the 
gathering and boosting, processing and transmission, and storage 
segments using both the single and multipollutant approaches. The EPA 
also determined that the costs of routing the captured gas from the 
centrifugal compressor wet seal degassing system to a control device 
are reasonable for the control of VOC for the gathering and boosting 
and processing segments using both the single and multipollutant 
approaches.

[[Page 74785]]

    Routing to a process. As discussed above, 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 put them to another beneficial use 
(referred to collectively as ``routing to a process''). One opportunity 
to meet this requirement would be to route emissions via a CVS or 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. For 
purposes of this analysis, we assumed that routing methane and VOC 
emissions from a wet seal fluid degassing system to a process reduces 
methane and VOC emissions in amounts greater than or equal to the 
emissions that would be reduced by a combustion device (i.e., greater 
than or equal to 95 percent) because emissions are conveyed via a CVS 
to an enclosed portion of a process that is operational where the 
emissions are predominantly recycled and/or consumed in the same manner 
as a material that fulfills the same function in the process. There are 
no secondary impacts with the option to control emissions from 
centrifugal wet seals by capturing gas and routing to a process. This 
alternative is an existing compliance option under NSPS OOOO and NSPS 
OOOOa. The EPA has historically assumed that the emissions reduced by 
routing to a process are 95 percent or greater. Our understanding is 
that routing gas from centrifugal compressor wet seal fluid degassing 
systems to a process generally requires the use of a VRU or other 
treatment to obtain a gas stream composition suitable to be returned to 
the sales line or for use for another purpose. Unlike pneumatic 
controllers and pneumatic pumps, (see section IV.D.1.b.iii of this 
preamble for controllers and section IV.E.1.b.iii of this preamble for 
pumps), the need to use a VRU or other treatment to obtain a gas stream 
with a composition suitable to be returned to the sales line could 
result in the use of treatment components that may vent to the 
atmosphere or the need for maintenance where, for example, the VRU may 
need to be bypassed for short periods (resulting in venting of some 
emissions to the atmosphere). The EPA solicits comment on its 
assumption that the emissions reduced by requiring the capture of gas 
and routing to a process is 95 percent or greater. The EPA also is 
soliciting comment on the prevalence of owners and operators complying 
with NSPS OOOO and NSPS OOOOa or other rules by routing emissions from 
the wet seal fluid degassing system to a process and the need for a VRU 
in order to be able to route emissions from the wet seal fluid 
degassing system to a process.
    The capital and annual costs for routing the seal oil degassing 
system to a process used in the updated analysis are based on 
information obtained from commenters.\185\ The updated capital costs 
are estimated to be $600,636, and the annual costs were estimated to be 
$85,517 (without savings), assuming a 10-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 thousand 
cubic feet (Mcf), which resulted in annual savings of $43,329 per year 
at gathering and boosting stations and $28,164 per year at processing 
plants.
---------------------------------------------------------------------------

    \185\ See Document ID No. EPA-HQ-OAR-2021-0317-1375.
---------------------------------------------------------------------------

    The updated analysis and cost effectiveness shown in Table 32 
indicates that routing emissions to a process is cost effective for the 
control of methane emissions for all of the evaluated segments using 
the single pollutant approach and is also cost effective for methane 
using the multipollutant approach for the gathering and boosting and 
processing segments. Similarly, the updated analysis indicates that 
routing emissions to a process for the control of VOC for the gathering 
and boosting and processing segments is cost effective using both the 
single and multipollutant approaches. However, as noted in the November 
2021 proposal, although capturing leaking gas and routing to a process 
has the advantage of both reducing emissions by at least 95 percent and 
capturing the natural gas (which results in natural gas savings), the 
EPA has received feedback that this option may not be viable in 
situations where downstream equipment capable of handling a low-
pressure fuel source is unavailable.
    Maintenance and repair activities to meet numerical emission limit. 
The EPA evaluated a third BSER option for this supplemental proposal 
not considered for the November 2021 proposal: maintenance and repair 
activities conducted to maintain emissions at or below 3 scfm, with 
annual flow rate monitoring on the wet seal degassing vent (also 
referred to as the numerical emission limit). We did so based on 
comments indicating that a threshold monitoring option is a more 
practical option for low-emitting centrifugal compressors with wet 
seals (as compared to the proposed requirement to route to a control 
device or to a process). This option would require owners and operators 
to perform periodic flow rate monitoring, as well as preventative 
maintenance and repair as necessary, on the wet seal degassing vent to 
ensure compliance with the 3 scfm emission limit. The 3 scfm volumetric 
flow rate emission limit is the same monitoring limit included in 
California's Regulation for Greenhouse Gas Emission Standards for Crude 
Oil and Natural Gas Facilities.\186\ California developed the 3 scfm 
emission standard because this was the equivalent to an average dry 
seal emission rate.\187\ The commenters specifically noted that low 
emissions from centrifugal compressors equipped with wet seals are 
largely a function of proper maintenance and that requiring a 95 
percent reduction standard or routing to a process creates an 
unintended result--the more careful an operator is with maintaining its 
wet seals, the more difficult and costly (on a cost-per-ton basis) 
controlling emissions in compliance with these requirements 
becomes.\188\
---------------------------------------------------------------------------

    \186\ California Code of Regulations, Title 17, Division 3, 
Chapter 1, Subchapter 10 Climate Change, Article 4, Subarticle 13, 
Section 95668(d)(4-9).
    \187\ State of California. Air Resources Board Public Hearing to 
Consider the Proposed Regulation for Greenhouse Gas Emission 
Standards for Crude Oil and Natural Gas Facilities. Staff Report: 
Initial Statement of Reasons. pg. 100.
    \188\ See Document ID No. EPA-HQ-OAR-2021-0317-1375.
---------------------------------------------------------------------------

    The types of maintenance and repair actions that may be needed to 
maintain emissions at or below 3 scfm will vary considerably. One 
commenter,\189\ a company that institutes an annual monitoring plan, 
indicated that the actions needed to reduce emissions or maintain a 
compressor such that it is low-emitting can range from correcting an 
identified issue immediately with minor maintenance, replacing o-rings 
on the filtration system, or having to rebuild the entire oil system. 
The costs associated with these maintenance and corrective actions vary 
significantly, from limited labor costs for a short repair activity to 
a significant capital cost of equipment and labor to repair and/or 
replace parts of the compressor. The EPA does not have specific costs 
for the range of maintenance and/or repairs

[[Page 74786]]

that may be necessary to maintain a flow rate at or below than 3 scfm. 
For the purposes of this analysis, the EPA selected an annual cost of 
$25,000 to represent the average cost of performing the monitoring and 
the necessary compressor wet seal maintenance. While we recognize 
certain types of maintenance or corrective actions may result in costs 
higher than $25,000 in one year, we believe that this is a conservative 
estimate to represent an average, annual cost. The EPA specifically 
solicits comments on the types of maintenance or corrective actions 
that may be required to maintain an emission rate of 3 scfm or less 
from wet seal degassing, along with representative costs.
---------------------------------------------------------------------------

    \189\ See Document ID No. EPA-HQ-OAR-2021-0317-1375.
---------------------------------------------------------------------------

    To estimate the cost effectiveness of this option, the EPA used the 
same updated GHGRP subpart W ``uncontrolled'' emissions discussed above 
for each centrifugal compressor with wet seals to represent baseline 
emissions. The ``after control'' emissions levels were calculated based 
on 3 scfm volumetric flow for 8,760 hours per year and the 
representative composition of the gas in the different segments. This 
calculation assumes that the emissions are, on average, 3 scfm for the 
entire year. This represents a conservative estimate, as one commenter 
\190\ indicated that the implementation of a similar program resulted 
in average measured emissions of less than 0.5 scfm for compressors 
with wet seals. Table 31 shows the baseline emissions, the emissions 
after implementation of the numerical emission limit, and the emission 
reductions for wet seal compressors.
---------------------------------------------------------------------------

    \190\ See Document ID No. EPA-HQ-OAR-2021-0317-1375.

    Table 31--Methane Baseline Emissions and Reductions After Implementation of the Numerical Emission Limit
               (Requirement To Maintain Flow Rate at or Below 3 scfm) Option--Wet Seal Compressors
----------------------------------------------------------------------------------------------------------------
                                                                     Methane emissions  (tpy)/
                                                                            compressor                Methane
                             Segment                             --------------------------------    emission
                                                                                       After         reduction
                                                                   Baseline \a\   implementation       (tpy)
----------------------------------------------------------------------------------------------------------------
Gathering and Boosting..........................................             251              27             224
Processing......................................................             163              27             136
Transmission and Storage........................................              66              30              35
----------------------------------------------------------------------------------------------------------------
\a\ From GHGRP subpart W (Reporting Years 2015 to 2020--Average).
\b\ Calculated assuming total gas emissions are 3 scfm for 8,760 hours.

    As noted above, we assumed annual maintenance, monitoring, and 
corrective action costs of $25,000 (without savings). Because the 
natural gas is not lost or combusted, the value of that natural gas 
represents a savings to owners and operators in the production 
(gathering and boosting) and processing segments. Savings were 
estimated using the emission reductions noted above and a natural gas 
price of $3.13 per Mcf, which resulted in annual savings of $33,719 per 
year at gathering and boosting stations and $20,486 per year at 
processing plants.
    As a result of the wet seal centrifugal compressor analysis and 
cost effectiveness shown in Table 32, the EPA has determined that the 
costs of implementing a numerical emission limit are reasonable for the 
control of methane for the gathering and boosting, processing, and 
transmission and storage segments using both the single and 
multipollutant approaches. The EPA has also determined that the costs 
of implementation of a numerical emission limit is reasonable for the 
control of VOC for the gathering and boosting and processing segments, 
using both the single and multipollutant approaches.
    The estimated cost effectiveness values that would be associated 
with: (1) Capturing and routing emissions to a combustion device, (2) 
capturing and routing emissions to a process, and (3) conducting 
maintenance and repair activities to meet a numerical emission limit (3 
scfm) (referred to as the ``numerical limit of 3 scfm'') for 
compressors with wet seals are provided in Table 32. In addition to the 
cost effectiveness values, Table 32 provides a conclusion regarding 
whether the estimated cost effectiveness value is within the range that 
the EPA has typically considered to be reasonable. The ``overall'' 
reasonableness determination is classified as ``Y'' if the cost 
effectiveness of either methane or VOC is within the range that the EPA 
considers reasonable for that pollutant, or ``N'' if both the methane 
and VOC cost effectiveness values are beyond the range that the EPA 
considers reasonable on a multipollutant basis.

    Table 32--Summary of Wet Seal Centrifugal Compressor Cost Effectiveness by Regulatory Option and Industry
                                                     Segment
----------------------------------------------------------------------------------------------------------------
                                           Cost effectiveness ($/ton) \a\--reasonable?
                                ----------------------------------------------------------------
   Segment/regulatory option            Single pollutant                 Multipollutant            Overall \a\
                                ----------------------------------------------------------------
                                     Methane           VOC           Methane           VOC
----------------------------------------------------------------------------------------------------------------
Gathering and Boosting:
    Regulatory Option One--              $515-Y        $1,853-Y          $258-Y          $927-Y               Y
     Route Emissions to
     Combustion Device.........
    Regulatory Option Two--               879-Y         3,163-Y           440-Y         1,582-Y               Y
     Route Emissions to the
     Process...................
    Regulatory Option Three--             111-Y           401-Y            56-Y           201-Y               Y
     Numerical Limit of 3 scfm.
Processing:

[[Page 74787]]

 
    Regulatory Option One--               793-Y         2,851-Y           396-Y         1,425-Y               Y
     Route Emissions to
     Combustion Device.........
    Regulatory Option Two--             1,353-Y         4,866-Y           676-Y         2,433-Y               Y
     Route Emissions to the
     Process...................
    Regulatory Option Three--             183-Y           660-Y            92-Y           330-Y               Y
     Numerical Limit of 3 scfm.
Transmission and Storage:
    Regulatory Option One--             1,973-Y        71,240-N           987-Y        35,620-N               Y
     Route Emissions to
     Combustion Device.........
    Regulatory Option Two--             3,369-N       121,607-N         1,684-Y        60,804-N               Y
     Route Emissions to the
     Process...................
    Regulatory Option Three--             711-Y        25,650-N           355-Y        12,825-N               Y
     Numerical Limit of 3 scfm.
----------------------------------------------------------------------------------------------------------------
\a\ For the gathering and boosting and processing segments, the owners and operators realize the savings for the
  natural gas that is not emitted and lost. The cost effectiveness values shown do not consider these savings.
  Note that the consideration of savings does not impact whether the cost effectiveness of any of these options
  falls within the ranges considered reasonable by the EPA.
\b\ For overall cost effectiveness to be considered reasonable, either the cost effectiveness of methane or VOC
  on a single pollutant basis must be within the ranges considered reasonable by the EPA, or the cost
  effectiveness of both methane and VOC on a multipollutant basis must be within the ranges considered
  reasonable by the EPA.

    Summary of Control Options Evaluated. In summary, the EPA evaluated 
three options for wet-seal centrifugal compressors: (1) Route emissions 
to a control device, (2) route emissions to a process, and (3) conduct 
maintenance and repair to maintain emissions at or below 3 scfm. The 
EPA's relevant analyses found that, for all segments, the costs in 
relation to the emission reductions were reasonable for all three 
options. However, the options to route captured gas to a control device 
or to a process achieve greater emission reductions than conducting 
maintenance and repair to maintain 3 scfm. For example, for the 
gathering and boosting segment, we estimated that the emissions reduced 
under the 3 scfm numerical limit option for a representative 
centrifugal compressor to be 89 percent, which is less than the routing 
to a control or process options, which achieve 95 percent.\191\ 
Therefore, the EPA finds that the standard of performance for each 
centrifugal compressor using a wet seal is 95 percent reduction of 
methane and VOC emissions based on a BSER of capturing and routing 
emissions from the wet seal degassing system to a combustion device for 
new sources in the gathering and boosting, processing, and transmission 
and storage segments. These reductions can also be achieved by routing 
emissions from the wet seal degassing system to a process. Therefore, 
as a compliance alternative, the EPA proposes to allow owners and 
operators to meet the 95 percent standard of performance by routing 
emissions from the wet seal degassing system to a process. The EPA 
notes that 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).
---------------------------------------------------------------------------

    \191\ U.S. Environmental Protection Agency. Supplemental 
Background Technical Support Document for the Proposed New Source 
Performance Standards (NSPS) and Emissions Guidelines (EG). 
Supporting Spreadsheets. August 2022.
---------------------------------------------------------------------------

    As discussed in section III.D of this preamble, NSPS KKK includes 
standards for controlling VOC emissions from centrifugal compressors 
with wet seals at natural gas processing plants. The standards provide 
several options for compliance, including: (1) Operating the 
centrifugal compressor with the barrier fluid at a pressure greater 
than the compressor stuffing box pressure; (2) equipping the 
centrifugal compressor with a barrier fluid system degassing reservoir 
that is routed to a process or fuel gas system or connected by a CVS to 
a control device that reduces VOC emissions by 95 percent or more; or 
(3) equipping the centrifugal compressor with a system that purges the 
barrier fluid into a process stream with zero VOC emissions to the 
atmosphere. NSPS KKK exempts compressors from these requirements if the 
compressor is either equipped with a CVS to capture and transport 
leakage from the compressor drive shaft back to a process or fuel gas 
system or to a control device that reduces VOC emissions by 95 percent, 
or if the compressor is designated for no detectable emissions.
    For NSPS OOOOb, we are proposing that emissions from each 
centrifugal compressor wet seal fluid degassing system require routing 
to a control device that achieves a 95 percent reduction of VOC and 
methane emissions, or by routing the emissions to a process that 
achieves 95 percent reduction of VOC and methane emissions. Proposed 
NSPS OOOOb is equivalent to one of the three options available under 
NSPS KKK.
    Owners and operators of wet seal centrifugal compressors have been 
complying with NSPS KKK since 1984. The EPA is requesting comments on 
whether it would provide more regulatory consistency for owners, 
operators, and implementing agencies if NSPS OOOOb were to incorporate 
all compliance options provided in NSPS KKK for wet seal centrifugal 
compressors at natural gas processing plants, as opposed to only 
proposing the compliance option of routing to a control or process 
proposed in this supplemental proposal.
ii. Lower-Emitting/Self-Contained Wet Seal Compressor Designs
    The November 2021 proposal solicited comment and information on 
lower-emitting wet seal compressor designs. Commenters \192\ reported 
that the process for wet seal degassing varies throughout the industry, 
and some manufacturers have a configuration that is essentially a 
closed process that ports the degassing emissions into the natural

[[Page 74788]]

gas line at the compressor suction. According to one industry commenter 
that employs this type of wet seal centrifugal compressor, this 
configuration typically includes a primary chamber where initial 
degassing occurs (and is recovered), and chamber(s) with air sparging 
to release and recover residual gas volumes entrained in the oil. 
Rather than venting all of the de-gassing volumes, the emissions are 
routed back to suction directly from the degassing/sparging chambers; 
the oil is ultimately recycled to the lube oil tank where any small 
amount of residual gas is released through a vent. One commenter stated 
that field evaluation is not always feasible for this closed system 
configuration but reported that testing and modeling demonstrates that 
the residual natural gas volume vented is very small (much less than 1 
percent of the total degassed natural gas volume). Another commenter 
requested that the EPA clarify that certain existing closed-loop wet 
seal systems be exempted from any regulatory proposal, or at a minimum, 
that such systems should be considered in compliance with the BSER 
currently applicable to wet seals.\193\
---------------------------------------------------------------------------

    \192\ See Document ID No. EPA-HQ-OAR-2021-0317-0415.
    \193\ See Document ID No. EPA-HQ-OAR-2021-0317-1375.
---------------------------------------------------------------------------

    Based on information indicating that closed-loop (self-contained) 
systems are inherently low-emitting, the EPA is proposing that these 
and similarly designed, self-contained wet seal centrifugal compressors 
represent/meet BSER (consistent with the routing to a process or 
control option). The EPA is proposing a definition for a ``self-
contained wet seal compressor'' as a ``wet seal compressor system that 
is a closed process that ports the degassing emissions into the natural 
gas line at the compressor suction (i.e., degassed emissions are 
recovered).'' The de-gas emissions are routed back to suction directly 
from the degassing/sparging chambers, and the oil is ultimately 
recycled to the lube oil tank where any small amount of residual gas is 
released through a vent. While the EPA recognizes the low emissions 
associated with these self-contained wet seal centrifugal compressors, 
we also recognize that there could be increased emissions due to leaks 
or malfunctions. Therefore, the proposed rule includes the requirement 
that owners or operators of self-contained wet seal centrifugal 
compressors must comply with the 3 scfm numerical emission standard 
described below for centrifugal compressors with dry seals. As 
indicated above, the intent of requiring compliance with the 3 scfm 
numerical standard is to ensure that self-contained wet seal 
compressors are operating properly (without leaks or malfunctions) 
since EPA understands that these compressors emit trivial amounts 
(i.e., achieve greater than 99 percent control) when properly operated. 
The EPA recognizes that where there is venting of any emissions from 
these compressors, emissions would more than likely be nondetectable 
for leaks, or would be at a rate lower than 3 scfm. The EPA solicits 
comment on, and support for, whether a lower numerical limit is needed 
to demonstrate proper operation of self-contained wet seal centrifugal 
compressors and/or equivalency to the BSER. The EPA also solicits 
comment on the feasibility of measuring the flow rate of self-contained 
wet seal centrifugal compressors at a rate lower than 3 scfm.
    In addition to wet seal compressor systems that are self-contained, 
one commenter \194\ reported information on another wet seal compressor 
that was inherently low-emitting. The commenter stated that it has 
facilities that use mechanical wet seals that generally have zero 
emissions. They explained that the metal (tungsten carbide) is seated 
against carbide, with oil pressing against the outside of the actual 
seal. They noted that because the oil is not in contact with the 
natural gas for these mechanical seals, these wet seals generally have 
zero degassing emissions. The commenter requested that the EPA exclude 
compressors utilizing mechanical wet seals from the wet seal compressor 
requirements otherwise applicable to wet seal compressors. The EPA is 
continuing to evaluate mechanical wet seal designs and the comments it 
has already received on the issue, and is soliciting additional 
information on these and other wet seal compressor designs (with 
supporting emissions information) that are inherently low-emitting 
under operating conditions.
---------------------------------------------------------------------------

    \194\ See Document ID No. EPA-HQ-OAR-2021-0317-0415.
---------------------------------------------------------------------------

iii. Dry Seal Compressors
    The EPA solicited 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 further requested information 
on whether owners and operators implement standard operating procedures 
to identify and correct operational or malfunctioning conditions that 
have the potential to increase emissions from dry seal systems, and 
whether EPA should consider evaluating BSER and developing NSPS 
standards for dry seal compressors.
    As the EPA has heard previously, the commenters noted that some dry 
seal compressors have higher emissions than compressors with wet seals. 
Based on input from a couple of commenters, we estimated the cost 
effectiveness of conducting preventative maintenance and repair, as 
needed, to maintain the volumetric flow rate from each centrifugal 
compressor that uses a dry seal at or below 3 scfm (as done for those 
with wet seals). The 3 scfm volumetric flow rate emission limit is the 
same monitoring limit included in California's Regulation for 
Greenhouse Gas Emission Standards for Crude Oil and Natural Gas 
Facilities for wet seal compressors.\195\ California developed the 3 
scfm emission standard because this was the equivalent to an average 
dry seal emission rate.\196\ The EPA did not evaluate any other control 
options for compressors with dry seals because they are inherently low-
emitting; increased emissions are generally the result of either 
unforeseen upset conditions or poor maintenance.
---------------------------------------------------------------------------

    \195\ California Code of Regulations, Title 17, Division 3, 
Chapter 1, Subchapter 10 Climate Change, Article 4, Subarticle 13, 
Section 95668(d)(4-9).
    \196\ State of California. Air Resources Board Public Hearing to 
Consider the Proposed Regulation for Greenhouse Gas Emission 
Standards for Crude Oil and Natural Gas Facilities. Staff Report: 
Initial Statement of Reasons. pg. 100.
---------------------------------------------------------------------------

    To estimate the cost effectiveness of this option, we used the 2019 
GHGI ``uncontrolled'' emissions for dry seal compressors as the 
baseline.\197\ The ``after control'' emissions levels were calculated 
based on a threshold of 3 scfm volumetric flow for 8,760 hours per year 
and the representative composition of the gas in the different 
segments. This calculation assumes that the emissions are, on average, 
3 scfm for the entire year. Table 33 shows the baseline emissions, the 
emissions after implementation of the numerical emission limit, and the 
emission reductions for dry seal compressors. The 3 scfm volumetric 
flow emission limit is the same as described above for wet seal 
centrifugal compressors.
---------------------------------------------------------------------------

    \197\ GHGI-Dry Seals.

[[Page 74789]]

      Table 33--Methane Baseline Emissions and Reductions After Implementation of the Annual Emission Limit
               (Requirement to Maintain Flow Rate at or Below 3 scfm) Option--Dry Seal Compressors
----------------------------------------------------------------------------------------------------------------
                                                                      Methane emissions (tpy)         Methane
                                                                 --------------------------------    emission
                             Segment                                                   After         reduction
                                                                   Baseline \a\   implementation       (tpy)
----------------------------------------------------------------------------------------------------------------
Gathering and Boosting..........................................              36               6              30
Processing......................................................              28               1              27
Transmission and Storage........................................              44               6              38
----------------------------------------------------------------------------------------------------------------
\a\ Based on GHGI. Emissions from dry-seal compressors are not estimated for gathering and boosting in the GHGI.
  The baseline emissions were calculated from the transmission and storage emissions (adjusted for the
  difference in gas composition).

    As discussed above for wet seal centrifugal compressors, there is a 
wide range in the types of repairs needed (and associated costs) for 
dry seal compressors. Given the lack of specific information on these 
repairs and costs, we assumed the annual costs to comply with this 
option to be $15,000 (without savings). This assumption is lower than 
the comparable assumption for wet seals because annual operating and 
maintenance costs for compressors with dry seals are lower than for 
compressors with wet seals. The EPA specifically solicits comments on 
the types of maintenance and corrective actions that may be required to 
maintain an emissions rate of 3 scfm or less from centrifugal 
compressors with dry seals, along with representative costs.
    Because natural gas emissions from a centrifugal compressor with 
dry seals would be reduced by maintaining the emission rate at or below 
3 scfm, the value of the retained natural gas that would have otherwise 
been emitted represents a savings to owners and operators in the 
production (gathering and boosting) and processing segments. Savings 
were estimated using the emission reductions noted above and a natural 
gas price of $3.13 per Mcf, which resulted in annual savings of $2,425 
per year at gathering and boosting stations and $1,170 per year at 
processing plants.
    The estimated cost effectiveness values that would be associated 
with conducting maintenance and repair activities to meet a numerical 
emission limit of 3 scfm for dry seal compressors are provided in Table 
34. In addition to the cost effectiveness values, Table 34 provides a 
conclusion regarding whether the estimated cost effectiveness value is 
within the range that the EPA has typically considered to be 
reasonable. The ``overall'' reasonableness determination is classified 
as ``Y'' if the cost effectiveness of either methane or VOC is within 
the range that the EPA considers reasonable for that pollutant, or 
``N'' if both the methane and VOC cost effectiveness values are beyond 
the range the EPA considers reasonable on a multipollutant basis.

                 Table 34--Summary of Dry Seal Centrifugal Compressor Cost Effectiveness by Industry Segment--Numerical Limit of 3 scfm
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                             Cost effectiveness ($/ton) \a\--reasonable?
                                                            ----------------------------------------------------------------------------
                          Segment                                      Single pollutant                       Multipollutant               Overall \b\
                                                            ----------------------------------------------------------------------------
                                                                  Methane              VOC              Methane              VOC
--------------------------------------------------------------------------------------------------------------------------------------------------------
Gathering and Boosting.....................................              930-Y            3,346-Y             $465-Y           $1,673-Y               Y
Processing.................................................            1,927-Y            6,933-N              964-Y            3,467-Y               Y
Transmission and Storage...................................              831-Y           29,997-N              415-Y           14,999-N               Y
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ For the gathering and boosting and processing segments, the owners and operators realize the savings for the natural gas that is not emitted and
  lost. The cost effectiveness values shown do not consider these savings. Note that the consideration of savings does not impact whether the cost
  effectiveness of any of these options falls within the ranges considered reasonable by the EPA.
\b\ For overall cost effectiveness to be considered reasonable, either the cost effectiveness of methane or VOC on a single pollutant basis must be
  within the ranges considered reasonable by the EPA, or the cost effectiveness of both methane and VOC on a multipollutant basis must be within the
  ranges considered reasonable by the EPA.

    Based on the consideration of the costs in relation to the emission 
reductions for methane shown in Table 34, the costs to implement the 
option to conduct preventative repair and maintenance so that each 
centrifugal compressor with a dry seal maintains a volumetric flow rate 
at or below 3 scfm is reasonable for all segments under both the single 
pollutant and multipollutant approaches. Based on the consideration of 
the costs in relation to the emission reductions for VOC, the costs of 
this option are reasonable for the gathering and boosting segment under 
both the single pollutant and multipollutant approaches. For the 
processing segment, the costs for reducing VOC emissions are reasonable 
under the multipollutant approach, but not the single pollutant 
approach. Costs for reducing VOC emissions would not be reasonable for 
implementing this approach for the transmission and storage segment. 
Given that the costs of conducting preventative repair and maintenance 
activities in order to maintain the volumetric flow rate from each 
centrifugal compressor with a dry seal at or below 3 scfm are 
reasonable, the EPA is proposing this option as BSER for compressors 
with dry seals.
c. Summary of 2022 Proposal
i. Affected Facility
    Based on changes made and discussed in section IV.G.1.b of this 
preamble, the EPA is proposing to redefine the affected facility to 
include dry seal centrifugal compressors in addition to wet seal 
centrifugal compressors. Therefore, a centrifugal compressor affected 
facility would be defined as a single centrifugal compressor. Further, 
the EPA is maintaining the proposed

[[Page 74790]]

specifications from the November 2021 proposal as applicable to 
centrifugal compressors located at well sites and centralized 
production facilities. Specifically, centrifugal compressors located at 
centralized production facilities would be considered affected 
facilities, while those located at well sites would not be affected 
facilities under NSPS OOOOb.
ii. Requirements
    Wet Seal Centrifugal Compressors. The EPA is proposing that owners 
or operators of centrifugal compressor affected facilities with wet 
seals must comply with the GHG and VOC standards by reducing methane 
and VOC emissions from each centrifugal compressor wet seal fluid 
degassing system by 95 percent. As an alternative to routing the CVS to 
a control device, an owner or operator may also route the CVS to a 
process or utilize a self-contained wet seal centrifugal compressor. If 
an owner or operator chooses to comply with this requirement either by 
using a control device to reduce emissions or by routing to a process 
to reduce emissions, an owner or operator must equip the wet seal fluid 
degassing system with a cover and the cover must be connected through a 
CVS meeting specified requirements (40 CFR 60.5411b(a) through (c)), 
such as design and operation with no identifiable emissions, as 
described in section IV.K of this preamble. If an owner or operator 
uses a self-contained wet seal centrifugal compressor, an owner or 
operator must ensure a volumetric flow rate at or below 3 scfm. In 
addition to the flow rate monitoring required every 8,760 hours, 
additional preventative or corrective measures may be required to 
ensure compliance.
    Dry Seal Centrifugal Compressors. The EPA is proposing that the 
standard of performance for centrifugal compressor dry seals is 3 scfm. 
The proposed BSER is for an owner or operator to conduct preventative 
maintenance and repair of their centrifugal compressors that use dry 
seals, as needed, to maintain the volumetric flow rate from each 
centrifugal compressor that uses a dry seal at or below 3 scfm. Owners 
and operators of centrifugal compressors with dry seals must conduct 
volumetric emissions measurements from each centrifugal compressor dry 
seal vent on or before 8,760 hours of operation or previous measurement 
and must use specified methods (similar to the flow rate monitoring 
requirements specified under the GHGRP subpart W) in doing so. Owners 
or operators must ensure that the volumetric emission measurements (in 
operating mode or in stand-by-pressurized-mode) from each centrifugal 
compressor dry seal vent are less than or equal to a flow rate 3 scfm 
(in operating or standby pressurized mode) or a manifolded dry seal 
compressor flow rate less than or equal to the number of compressors 
multiplied by 3 scfm (in operating or standby pressurized mode). As 
discussed in section IV.I the EPA is proposing the use of volumetric 
flow rate which meet the requirements of Method 2D (40 CFR part 60, 
appendix A) for testing emissions from reciprocating compressor rod 
packing and the use of a high-volume sampler to measure the emissions 
from either the reciprocating compressor rod packing or centrifugal 
compressor seal vent (dry seals for NSPS OOOOb and all centrifugal 
compressor wet and dry seals for EG OOOOc). For the high-volume 
sampler, instead of relying on manufacturer defined procedures required 
in GHGRP Subpart W, the EPA is proposing a defined set of procedures 
and performance objectives to ensure consistent application of these 
samplers. In an effort to allow for additional innovation for these 
types of measurements, the EPA is also proposing to allow other 
methods, subject to Administrator approval, that have been validated 
according to Method 301 (40 CFR part 63, appendix A). Preventative 
maintenance or other corrective actions may be necessary (in addition 
to the monitoring every 8,760 hours of operation) in order for owners 
or operators to ensure compliance at all times (consistent with the 
general duty clause 40 CFR 60.5470b(b)) with the required flow rate of 
3 scfm or less.
    Recordkeeping and Reporting Requirements. Specific recordkeeping 
and reporting requirements would also apply for each wet seal 
centrifugal compressor affected facility. Specifically, records and 
annual reporting that identifies each centrifugal compressor using a 
wet seal system that was constructed, modified, or reconstructed during 
the reporting period would be required. In instances where a deviation 
from the standard occurred during the reporting period and recorded, an 
owner or operator would be required to provide information on the date 
and time the deviation began, the duration of the deviation, and a 
description of the deviation.
    For centrifugal compressors where compliance is achieved by using a 
control device to reduce emissions, the following information would be 
required in the annual report: dates of the cover and CVS inspections, 
whether defects or leaks are identified, and the date of repair or the 
date of anticipated repair if repair is delayed. Where bypass 
requirements apply, reporting of the date and time of each bypass alarm 
or each instance the key is checked out would be required.
    If complying with the centrifugal compressor requirements for wet 
seal fluid degassing system by reducing VOC and methane emissions by 95 
percent using a control device tested by the device manufacturer, the 
annual report must include: the identification of the compressor with 
the control device and the make, model, and date of purchase of the 
control device. An owner or operator would also be required to record 
and report the following: (1) Each instance where there is an inlet gas 
flow rate exceedance, (2) each instance where there is no indication of 
a pilot flame, and (3) each instance where there was a visible 
emissions exceedance. The annual report would be required to include 
the date and time the deviation began, the duration of the deviation, 
and a description of the deviation. Finally, for each visible emissions 
test following return to operation from a maintenance or repair 
activity, the annual report would be required to include the date of 
the visible emissions test, the length of the test, and the amount of 
time visible emissions were present.
    If complying with the centrifugal compressor requirements for a wet 
seal fluid degassing system by reducing VOC and methane emissions by 95 
percent by using a control device not tested by the device 
manufacturer, the following information must be included in the annual 
report: identification of the control device not tested by the device 
manufacturer, the identification of the compressor with the tested 
control device, the date the performance test was conducted, the 
pollutant(s) tested, and the performance test report conducted to 
demonstrate that the control device is achieving, at a minimum, the 
required 95 percent reduction.
    For each dry seal centrifugal compressor affected facility and 
self-contained wet seal centrifugal compressor affected facility, 
owners and operators would be required to track and report the 
cumulative number of hours of operation since startup since the 
previous screening/volumetric emissions measurement in order to 
demonstrate compliance with their volumetric emissions measurements. 
Additionally, a description of the method used and the results of the 
volumetric emissions measurement or

[[Page 74791]]

emissions screening, as applicable, would be required in the annual 
report.
2. EG OOOOc
a. Summary of 2021 Proposal
    The summary of the November 2021 proposal for EG OOOOc is 
consistent with what was proposed for NSPS OOOOb (see section IV.G.1.a 
of this preamble).
b. Changes to Proposal and Rationale
    The EPA is proposing changes and specific clarifications to the 
November 2021 proposal presumptive standards for the EG OOOOc. 
Specifically, we are proposing to: (1) Revise the designated facility 
definition to include all centrifugal compressors, (2) include a 
numerical emission limit requirements for dry and wet seal compressors, 
and (3) allow owners and operators the option to comply with EG OOOOc 
by reducing methane emissions by 95 percent by either routing to a 
control device or to a process. The basis for these changes is 
presented below.
    Wet Seal Centrifugal Compressors. Industry commenters expressed 
particular concern about having to retrofit existing wet seal 
centrifugal compressors to accommodate the November 2021 proposal that 
would have required owners and operators to reduce methane emissions 
from each centrifugal compressor wet seal fluid degassing system by 95 
percent or greater. One commenter \198\ stated that the November 2021 
proposal for wet seal centrifugal compressors would require 
installation of an enclosed combustion device or a process flare in 
nearly every case for their facilities. The commenter noted that, while 
theoretically an enclosed combustion device could be installed to 
control the minimal emissions on an individual wet seal compressor, a 
combustion device cannot be located just anywhere, especially not in 
close proximity to a transmission compressor station. The commenter 
noted that a combustion device must be strategically located away from 
combustible materials, which typically requires a significant 
footprint, aboveground piping (above roadways), and in an elevated 
location. In order to install such a device, they stated that they 
would likely have to apply for and receive state and local permit 
modifications, which are not certain to be approved in each case. The 
commenter also stated that routing to a control device could present 
safety concerns. For example, they note that attempts to capture a low-
pressure natural gas vent stream, such as that of the wet seal, could 
result in inducing air into the gas stream, potentially creating a 
combustible mixture. The commenter reports that one manufacturer has 
previously ``caution[ed] the use of flaring with gas seal vented 
emissions due to risk of the potential explosive hazard and back-
flashing.'' \199\ The commenter reports that it is ``[their] view 
(concurrent with many users of our equipment) [that] flaring of 
compressor seal emissions can introduce inherently dangerous conditions 
with the potential for back-flashing and serious risk of explosion. 
Solar therefore discourages flaring for this reason although some 
customers have successfully implemented it.''
---------------------------------------------------------------------------

    \198\ See Document ID No. EPA-HQ-OAR-2021-0317-1375.
    \199\ See Document ID No. EPA-HQ-OAR-2021-0317-1375.
---------------------------------------------------------------------------

    With respect to the routing to process option, the same commenter 
notes that, while theoretically feasible, a low flow gas stream (like 
their facilities' gas streams) cannot be safely or technically re-
introduced back into their processes without significant, resource-
intensive, attention to that minor emissions stream. According to the 
commenter, the unintended result would be that the additional equipment 
that would need to be installed to accomplish this routing back to 
process would not only be costly (discussed below) but could also 
result in additional emissions from other sources.
    Based on these concerns, for existing wet seal centrifugal 
compressors, the EPA is no longer proposing that BSER is 95 percent 
reduction of methane emissions by routing emissions to a control device 
or process. Instead, based on the updated analysis presented in this 
supplemental proposal, the EPA is proposing that the standard of 
performance for existing sources is a numerical emission limit of 3 
scfm; the BSER is for an owner or operator to conduct preventative 
maintenance and repair of their centrifugal compressors that use wet 
seals, as needed, to maintain the volumetric flow rate from each 
centrifugal compressor that uses a wet seal at or below 3 scfm. Owners 
or operators would be required to conduct volumetric flow rate 
measurements at least every 8,760 hours. As a compliance alternative, 
the EPA is proposing to allow owners and operators the option to reduce 
methane emissions by 95 percent or greater by routing emissions to a 
control device or to a process, which would achieve emissions 
reductions equal to or greater than the standard of performance of 3 
scfm. The cost of application of the numerical emission limit 
requirement at an existing source is the same as at a new source, and 
the methane cost effectiveness would be the same as discussed in the 
previous section for wet seal centrifugal compressors subject to NSPS 
OOOOb. The cost effectiveness (without natural gas savings) of 
complying with the numerical emission limit for methane emissions is 
approximately $111 per ton of methane emissions reduced for the 
gathering and boosting segment, $183 per ton of methane emissions 
reduced for the processing segment, and $711 per ton of methane 
emissions reduced for the transmission and storage segment. Considering 
natural gas savings, the cost effectiveness of complying with the 
numerical emission limit for methane emissions is an overall net 
savings for the gathering and boosting segment, and $28 per ton of 
methane emissions reduced for the processing segment.
    As discussed in section IV.G.1.i of this preamble NSPS KKK includes 
standards for controlling VOC emissions from centrifugal compressors 
with wet seals at natural gas processing plants. The standards provide 
several options to comply, including: (1) Operating the centrifugal 
compressor with the barrier fluid at a pressure that is greater than 
the compressor stuffing box pressure; (2) equipping the centrifugal 
compressor with a barrier fluid system degassing reservoir that is 
routed to a process or fuel gas system or connected by a CVS to a 
control device that reduces VOC emissions by 95 percent or more; or (3) 
equipping the centrifugal compressor with a system that purges the 
barrier fluid into a process stream with zero VOC emissions to the 
atmosphere. NSPS KKK exempts compressors from these requirements if the 
compressor is either equipped with a CVS to capture and transport 
leakage from the compressor drive shaft back to a process or fuel gas 
system or to a control device that reduces VOC emissions by 95 percent, 
or if the compressor is designated for no detectable emissions.
    For EG OOOOc, the proposed presumptive standard would be a 
numerical emission limit of 3 scfm and include an alternative 
compliance method of reducing methane emissions by 95 percent by 
routing to a control or process. The proposed presumptive standard of 3 
scfm is less stringent than the regulatory compliance options under 
NSPS KKK for centrifugal compressor at natural gas processing plants.
    Owners and operators of wet seal centrifugal compressors have been 
complying with NSPS KKK since 1984. The EPA is requesting comments on 
whether it would provide more

[[Page 74792]]

regulatory consistency for owners, operators, and implementing agencies 
if EG OOOOc were to incorporate all compliance options provided in NSPS 
KKK for wet seal centrifugal compressors at natural gas processing 
plants instead of the 3 scfm emission limitation.
    Dry Seal Compressors. The application of the numerical emission 
limit option at an existing source is the same as at a new source 
because no additional equipment must be installed in order to comply 
with the standards. Therefore, the cost of control would also be the 
same (see section IV.G.1.b.i of this preamble). As a result, based on 
the consideration of the costs in relation to the emission reductions 
for methane, the costs to implement the numerical emission limit is 
reasonable for all segments. Given that the costs of reducing methane 
emissions by the implementation of the numerical emission limit are 
reasonable, the EPA is proposing this option as BSER for existing 
centrifugal compressors with dry seals.
c. Summary of 2022 Proposal
i. Designated Facility
    Based on changes made and discussed under section IV.F.2.b of this 
preamble, the EPA is proposing to redefine the designated facility to 
include dry seal compressors in addition to wet seal compressors. 
Specifically, the designated facility is defined as a single 
centrifugal compressor. Further, the EPA is proposing that centrifugal 
compressors located at centralized production facilities would be 
designated facilities, while centrifugal compressors located at well 
sites would not be designated facilities, consistent with the November 
2021 proposal.
ii. Requirements
    Wet and Dry Seal Centrifugal Compressors. The EPA is proposing that 
owners or operators of centrifugal compressors with wet and dry seals 
be required to conduct volumetric emission measurements (in operating 
mode or in stand-by-pressurized-mode) from each centrifugal compressor 
dry and wet seal vent using specified methods (similar to the flow rate 
monitoring requirements specified under GHGRP subpart W). Owners and 
operators would be required to conduct volumetric emissions 
measurements from each centrifugal compressor wet and dry seal vent on 
or before 8,760 hours of operation or previous measurement.
    The volumetric emissions measurement of the centrifugal compressor 
wet and dry seal vent must be maintained to be less than or equal to a 
flow rate of 3 scfm (in operating or standby pressurized mode) or a 
manifolded dry and wet seal compressor flow rate less than or equal to 
the number of compressors multiplied by 3 scfm (in operating or standby 
pressurized mode). The same requirements specified in IV.G.1.c of this 
preamble for dry seal compressors complying with the numerical emission 
limit being proposed for NSPS OOOOb are being proposed for self-
contained wet seal centrifugal compressors under NSPS OOOOb and for dry 
and wet seal centrifugal compressors complying with this option under 
EG OOOOc.
    Compliance Alternative for Wet Seal Compressors. As a compliance 
alternative to maintaining a flow rate at or below 3 scfm, the EPA is 
proposing that an owner or operator of a centrifugal compressor 
equipped with wet seals can comply with EG OOOOc by reducing methane 
emissions from each centrifugal compressor wet seal fluid degassing 
system by 95 percent, which achieves emission reductions greater than 
or equal to the 3 scfm proposed presumptive standard. Options to meet 
this emission reduction requirement include routing emissions via a CVS 
to a control device or to the process. This standard can also be met by 
an owner or operator utilizing a self-contained wet seal centrifugal 
compressor. The same requirements specified in IV.G.1.c for wet seal 
compressors complying with the requirements to reduce methane emissions 
from each centrifugal compressor wet seal fluid degassing system by 95 
percent are being proposed for wet seal compressors complying with this 
option under EG OOOOc.

H. Combustion Control Devices

1. November 2021 Proposal
    The EPA proposed requiring 95 percent methane and VOC reduction for 
certain affected/designated facilities (i.e., storage vessels, wet seal 
centrifugal compressors, and associated gas from oil wells when a sales 
line is not available) and solicited comments on several aspects of the 
operational efficiency of combustion control devices and methods to 
ensure continuous compliance with the required control efficiency. 
Specifically, in the November 2021 proposal, the EPA solicited comments 
on whether additional measures to ensure proper performance of flares 
would be appropriate to ensure that flares meet the current 95 percent 
control requirement. The EPA solicited similar comments for enclosed 
combustion devices, particularly regarding creating comprehensive 
specifications for an operating envelope under which a make/model can 
achieve 98 percent reduction. The EPA also solicited comments on the 
practicality of requiring combustion and non-combustion control systems 
to meet a 98 percent reduction control requirement under operating 
conditions present in the oil and gas industry. Finally, the EPA 
solicited comment on new technologies that would provide real-time or 
near real-time measurement of control efficiency, particularly for 
flares.
2. Changes From November 2021 Proposal
    The EPA received comments on most aspects of the solicitation for 
comments in the November 2021 proposal related to combustion control 
devices, ranging from opposition to requirements as specific as 
continuous pilots to recommendations for the use of advanced 
technologies to continuously monitor flare combustion efficiency. As 
described throughout this section, the EPA is proposing specific 
additional requirements in response to comments on the November 2021 
proposal and clarifying other requirements that were proposed in that 
action.
    In this supplemental proposal, the EPA is proposing requirements 
for various combustion control devices to develop consistent 
monitoring, recordkeeping, and reporting requirements, regardless of 
the affected/designated facility with which the control device is 
associated. This is different than the compliance requirements for 
control devices in NSPS OOOOa, which has separate requirements for 
control devices used on storage vessel affected facilities, than those 
used on centrifugal compressor affected facilities. The proposed 
monitoring, recordkeeping, and reporting requirements related to 
control devices are designed to ensure that these systems achieve the 
required control efficiency, and they were established using methods 
that limit the burden for owners and operators, while still ensuring 
compliance with the required control efficiency.
    Flares. The EPA is proposing to include in both NSPS OOOOb and EG 
OOOOc more comprehensive monitoring requirements for flares as 
referenced to the General Provisions at 40 CFR 60.18. Specifically, the 
General Provisions at 40 CFR 60.18 indicate four criteria needed for 
good flare performance. These are: (1) Continuous pilot flame; (2) no 
visible emissions except for a total of 5 minutes in a 2-

[[Page 74793]]

hour period; (3) minimum net heating value of gas sent to the flare; 
and (4) maximum flare tip velocity. In NSPS OOOO and NSPS OOOOa, the 
compliance requirements for flares include criteria to address 
compliance with items 1 and 2 but do not include any requirements that 
would ensure compliance with items 3 and 4 for any affected facilities 
which reference flares as a control device option. That is, those 
rules, which adopt by reference the flare requirements in 40 CFR 60.18 
(i.e., the General Provisions to 40 CFR part 60) do not include 
specific requirements specifying the minimum net heating value of gas 
sent to the flare or the maximum flare tip velocity. One commenter on 
the November 2021 proposal stated that the EPA must establish 
continuous monitoring requirements for flares regardless of the control 
efficiency required.\200\ One commenter noted that the General 
Provisions at 40 CFR 60.18 state that the referencing subpart will 
specify the monitoring requirements and indicated that the EPA must 
specify these requirements in the new standards.\201\ The EPA agrees 
with these commenters, especially noting that recent studies suggests 
that 10 percent of flares in the Permian basin are either unlit or are 
only burning a portion of the gas sent to the flare.\202\ Consequently, 
the EPA concludes that the current operating and monitoring practices 
and requirements for well sites and centralized production facilities 
are not adequate to ensure flare control systems are operated 
efficiently and is therefore, proposing compliance requirements to 
ensure all aspects of the General Provisions at 40 CFR 60.18 are met at 
all times. These include requirements to ensure a pilot flame is 
present at all times through monitoring with a device such as a 
thermocouple, ultraviolet beam sensor, or infrared sensor and 
monitoring of NHV through use of a calorimeter, unless a demonstration 
has been made that the NHV of the inlet gas to the flare consistently 
exceeds the operating limit established in the rule. In other 
rulemakings, for example recent amendments to the refining \203\ and 
chemical sector \204\ rules, monitoring of the net heating value in the 
combustion zone, instead of the heating value of the vent gas is 
required. While this is important for an assisted flare, we anticipate 
the oil and gas source category predominately will use unassisted 
flares, because air-assisted flares require electricity and not all 
sites will have access to electricity. The EPA finds that the 
provisions at 40 CFR 60.18 are sufficient for unassisted flares because 
the heat content of the gas at the flame is not diluted by an assist 
stream of gas or air. The EPA requests comment on the universe of 
unassisted and assisted flares in the oil and gas sector. See section 
IV.H.3 of this preamble for details of the proposed compliance 
requirements for flares.
---------------------------------------------------------------------------

    \200\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0844 and EPA-HQ-
OAR-2021-0317-1282.
    \201\ See Document ID No. EPA-HQ-OAR-2021-0317-1282.
    \202\ Permian Methane Analysis Project (PermianMAP) reporting 
the results of 4 Environmental Defense Fund (EDF) surveys of over a 
thousand flare stacks from February to November 2020. See https://www.permianmap.org/flaring-emissions.
    \203\ See 80 FR 75266 (December 1, 2015).
    \204\ See 85 FR 49132 (August 12, 2020).
---------------------------------------------------------------------------

    Enclosed Combustors. The EPA is proposing the same monitoring 
requirements for enclosed combustion devices for all affected 
facilities that use such devices to meet the applicable standards. We 
are also proposing monitoring requirements for enclosed combustion 
devices (which are not tested by the manufacturer) for which the 
performance test does not correlate the combustion efficiency achieved 
by the combustion device with temperature. (i.e., temperature is not 
well correlated with combustion efficiency). NSPS OOOO and OOOOa have 
separate monitoring requirements for control devices used for 
centrifugal compressor affected facilities than for control devices 
used for storage vessel affected facilities. This difference goes back 
to the EPA's understanding of the landscape of the oil and gas industry 
during the rulemaking process for NSPS OOOO and subsequent amendments 
through 2016 which resulted in the promulgation of NSPS OOOOa. 
Centralized production facilities were not identified within the EPA's 
emissions inventory, and the EPA found that storage vessels were mostly 
located at well sites which did not have other affected facilities 
requiring control. The EPA expected these sites to take advantage of 
the reduced compliance burden by using control devices tested by the 
manufacturer. Further, during the reconsideration of aspects of NSPS 
OOOO, the EPA determined that streamlined compliance options were 
warranted for storage vessel affected facilities, in part because of 
implementation issues at remote sites and the large number of storage 
vessel affected facilities.\205\ In this action, the EPA is proposing 
standards for additional affected facilities at well sites (i.e., oil 
wells with associated gas that is routed to a control device) and 
defining centralized production facilities (which include storage 
vessel and compressor affected facilities requiring 95 percent 
control). The EPA finds that the rationale used in NSPS OOOO and NSPS 
OOOOa supporting streamlined monitoring for storage vessels no longer 
holds true. Remote well sites still exist, but these sites also may be 
subject to standards for oil well with associated gas and the 
compliance burden is shared between those affected facilities to ensure 
emissions from both storage vessels and oil wells with associated gas 
are reduced by 95 percent. Further, the centralization of production 
activities makes moot the concern about remote wells sites for these 
centralized production facilities. As mentioned previously, recent 
studies such as the study conducted in the Permian, indicate pervasive 
issues with combustion sources \206\ and enforcement activities 
conducted by the EPA and states have uncovered issues with proper 
operation of enclosed combustors on storage vessels.\207\ For these 
reasons, the EPA is proposing to align the monitoring requirements in 
NSPS OOOOb and EG OOOOc to ensure that all control devices are subject 
to the same monitoring requirements, regardless of the affected 
facility being controlled.
---------------------------------------------------------------------------

    \205\ See 78 FR 58438 (September 23, 2013) and 81 FR 35897 (June 
3, 2016).
    \206\ Permian Methane Analysis Project (PermianMAP) reporting 
the results of 4 Environmental Defense Fund (EDF) surveys of over a 
thousand flare stacks from February to November 2020. See https://www.permianmap.org/flaring-emissions.
    \207\ ``EPA Observes Emissions from Controlled Storage Vessels 
at Onshore Oil and Gas Production Facilities.'' See https://www.epa.gov/sites/default/files/2015-09/documents/oilgascompliancealert.pdf.
---------------------------------------------------------------------------

    For thermal oxidizers/enclosed combustors for which temperature is 
correlated with combustion efficiency and for catalytic oxidizers, the 
EPA is proposing to include in NSPS OOOOb and EG OOOOc the same 
monitoring requirements as required under NSPS OOOOa for centrifugal 
compressor affected facilities, and consistent with the rationale in 
this discussion, we are proposing to require these monitoring 
requirements for all enclosed combustion devices, regardless of the 
affected facility being controlled. Further, the EPA is proposing 
additional initial compliance requirements for vapor recovery devices 
and catalytic vapor incinerators, to ensure owners and operators have a 
clear roadmap for initial compliance. Similarly, the EPA is proposing 
additional continuous compliance requirements which specify how to 
determine continuous compliance with the requirements for

[[Page 74794]]

catalytic vapor incinerators, regenerative-type carbon adsorption 
systems, and carbon management for regenerative-type and 
nonregenerative-type carbon adsorption systems.
    The EPA is also proposing monitoring requirements for enclosed 
combustion devices not tested by a manufacturer for which temperature 
is not well correlated with combustion efficiency. For enclosed 
combustors for which temperature is not well correlated with combustion 
efficiency, the EPA is proposing to incorporate requirements similar to 
those proposed for flares, as the operation of these devices is similar 
to the operation of a flare in that the combustibility of the gas 
(NHV), operation without smoking (visible emissions) and a continuous 
burning pilot flame are fundamental to ensuring 95 percent combustion. 
One commenter suggested that monitoring of the pilot flame for enclosed 
combustors was sufficient to provide assurance of effective emission 
control.\208\ However, no data were provided to support this assertion 
and available data and combustion theory science suggests that the net 
heating value of the gas being sent to the combustor is also critical 
to ensure proper combustion. As good combustion depends upon the fuel 
having a minimum amount of heat content, if the gases from the affected 
facility required to be controlled have low heat content at times, then 
auxiliary fuel may be necessary to ensure good combustion during those 
periods. That is, the same requirements that are needed to ensure 
proper performance of flares also apply to enclosed combustors. Because 
enclosed combustors often are associated with storage vessels which 
have variable emissions events depending on working, breathing, 
standing, or flashing losses, the EPA also is proposing that enclosed 
combustors monitor inlet flow rate to ensure the control device 
operates within the compliance envelope at which compliance with the 95 
percent control efficiency was demonstrated.
---------------------------------------------------------------------------

    \208\ See Document ID No. EPA-HQ-OAR-2021-0317-0749.
---------------------------------------------------------------------------

    Condensers and Carbon Adsorption Systems. The EPA is proposing 
consistent monitoring requirements for condensers and carbon adsorption 
systems independent of the affected facility. NSPS OOOOa has specific 
compliance requirements for condensers and carbon adsorption systems 
used to control emissions from centrifugal compressor affected 
facilities but less specific compliance requirements for vapor recovery 
devices used for storage vessel affected facilities. In NSPS OOOOa, 
owners and operators are required to conduct specific parameter 
monitoring for condensers and carbon adsorption systems used to control 
emissions from centrifugal compressor affected facilities, while owners 
and operators are only required to conduct monthly inspections ``. . . 
to ensure physical integrity of the control device according to the 
manufacturer's instructions'' for vapor recovery devices used to 
control storage vessel affected facilities. Monthly inspections do not 
ensure the condenser temperature is adequate or that the carbon beds 
are changed out or regenerated at a frequency to ensure the control 
device is achieving at least 95 percent control efficiency. Therefore, 
in NSPS OOOOb and EG OOOOc, the EPA is proposing that all affected and 
designated facilities that use condensers or carbon adsorption systems 
must meet the same monitoring requirements as outlined for centrifugal 
compressor affected facilities in NSPS OOOOa.
    Manufacturer Tested Control Devices. The EPA is proposing to 
require the same initial requirements for manufacturer testing of 
control devices and ancillary monitoring requirements as required in 
NSPS OOOO and NSPS OOOOa. In NSPS OOOO and NSPS OOOOa, the EPA included 
this alternative to minimize issues associated with performance testing 
of certain combustion control devices in the field. The requirements 
were based on similar requirements in the oil and natural gas NESHAP 
(40 CFR part 63, subparts HH and HHH) and which had been successfully 
implemented for some time prior to the promulgation of NSPS OOOO and 
NSPS OOOOa. In the 2011 proposal of the provisions for NSPS OOOO, we 
stated ``[w]e believe that testing units that are not configured with a 
distinct combustion chamber present several technical issues that are 
more optimally addressed through manufacturer testing, and once these 
units are installed at a facility, through periodic inspection and 
maintenance in accordance with manufacturers' recommendations. One 
issue is that an extension above certain existing combustion control 
device enclosures will be necessary to get adequate clearance above the 
flame zone. Such extensions can more easily be configured by the 
manufacturer of the control device rather than having to modify an 
extension in the field to fit devices at every site. Issues related to 
transporting, installing and supporting the extension in the field are 
also eliminated through manufacturer testing. Another concern is that 
the pitot tube used to measure flow can be altered by radiant heat from 
the flame such that gas flow rates are not accurate. This issue is best 
overcome by having the manufacturer select and use the pitot tube best 
suited to their specific unit. For these reasons, we believe the 
manufacturers' test is appropriate for these control devices with 
ongoing performance ensured by periodic inspection and maintenance. (76 
FR 52785; August 23, 2011).
    Control Efficiency. As mentioned earlier in this section, the EPA 
requested comment on whether the EPA should require 98 percent 
reduction of methane and VOC emissions instead of 95 percent in the 
November 2021 proposal. The EPA received comments stating that flares 
can be designed to meet 98 percent control efficiency,\209\ but we also 
received comments stating that variability in gas flow, pressure, and 
quality would present challenges to achieving 98 percent control 
efficiency, especially at low production wells.\210\
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    \209\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0604, EPA-HQ-
OAR-2021-0317-0605, EPA-HQ-OAR-2021-0317-0844, and EPA-HQ-OAR-2021-
0317-1286.
    \210\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0599, EPA-HQ-
OAR-2021-0317-0808, and EPA-HQ-OAR-2021-0317-0831.
---------------------------------------------------------------------------

    The EPA evaluated the costs associated with requiring 98 percent 
reduction of methane and VOC emissions from storage vessels in order to 
compare the cost-effectiveness for this option against the costs 
associated with requiring 95 percent reduction. While the analysis was 
specific for storage vessels, the conclusions drawn from this analysis 
are generally applicable to other affected facilities because the size 
range of control devices evaluated cover the range of controls used for 
other affected facilities. Based on this evaluation, we conclude that 
the additional reduction is not cost effective and would therefore not 
represent the BSER for affected sources requiring an emissions 
reduction through the use of a pollution control device. Specifically, 
using this example for storage vessel affected facilities, the EPA 
added the additional monitoring and operational costs expected to 
ensure a 98 percent minimum destruction efficiency and found that it 
would not be cost-effective to require control of storage vessels with 
the potential for VOC emissions below 12 tpy or methane emissions below 
40 tpy. However, at 95 percent reduction, it is considered cost-
effective to require control of storage vessels with potential VOC 
emissions of 6 tpy and methane

[[Page 74795]]

emissions of 20 tpy.\211\ Therefore, requiring 98 percent reduction of 
methane and VOC results in the control of fewer storage vessels, and 
thus result in fewer overall emissions reductions. Consequently, the 
EPA is proposing to maintain that the BSER for storage vessel affected 
facilities is 95 percent reduction, as described in section IV.J of 
this preamble. Because the analysis conducted covers the range of 
control device sizes utilized by other affected facilities, similar 
impacts on the BSER analysis are expected. Furthermore, because 
individual sites would utilize a single control device for all 
affected/designated facilities, it does not make sense to require 
different emissions reduction standards for different affected/
designated facilities. For more detail on the analysis conducted to 
assess the costs of control device monitoring see memorandum Analysis 
of Monitoring Costs to Ensure 98 Percent Destruction Efficiency, 
available in the docket for this action (Docket ID No. EPA-HQ-OAR-2021-
0317).
---------------------------------------------------------------------------

    \211\ The costs associated with the monitoring requirements 
necessary to ensure a 95 percent reduction in methane and VOC 
emissions is achieved were included in the cost analysis provided in 
the November 2021 proposal. See the 2021 TSD for additional details 
at Document ID No. EPA-HQ-OAR-2021-0317-0166 and accompanying 
spreadsheets at Document ID No. EPA-HQ-OAR-2021-0317-0039.
---------------------------------------------------------------------------

3. Summary of Proposed Requirements for NSPS OOOOb and EG OOOOc
    The EPA is proposing that control devices used for any affected 
facility must demonstrate that they meet a 95 percent VOC and methane 
emission reduction requirement through a performance test (or for 
condensers and carbon absorbers, through a design evaluation) or 
manufacturer's performance test.
    In NSPS OOOOb and EG OOOOc, we are proposing the same control 
device requirements for thermal vapor incinerators (including thermal 
oxidizers and enclosed combustors) for which temperature is correlated 
with destruction efficiency, catalytic vapor incinerators, condensers, 
and carbon adsorption systems as were required in NSPS OOOOa (for 
centrifugal compressor affected facilities). We are proposing that 
these requirements apply to all affected facilities complying with the 
standards by using one of these control devices.
    The EPA is proposing requirements for flares to be designed and 
operated according to the provisions in 40 CFR 60.18 for all flares, 
regardless of the affected facility type, except as noted below for 
pressure-assisted devices. Further, we are proposing to require these 
same general requirements for enclosed combustors not tested by the 
manufacturer and for which temperature is not correlated with control 
device performance. NSPS OOOO and NSPS OOOOa do not include criteria to 
determine that temperature is (or is not) correlated with control 
device performance. Criteria where temperature is well correlated could 
include requirements that air flow to the burner is controlled and that 
there is sufficient refractory in the stack to maintain high 
temperature even at low flows. The EPA requests comment on whether 
criteria should be developed for NSPS OOOOb and EG OOOOc, which 
delineate when temperature is (or is not) correlated with control 
device performance, and if so, in addition to the criteria above, what 
criteria would be appropriate. The EPA is proposing to include 
consistent initial and continuous compliance requirements to ensure 
flares and enclosed combustion devices are maintaining efficient 
combustion. As discussed previously in this section, there are 4 
critical requirements in 40 CFR 60.18 that must be met to ensure proper 
destruction efficiency.\212\ The proposed continuous compliance 
requirements for each of these critical elements are described in the 
following paragraphs.
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    \212\ The four requirements are: (1) Continuous pilot flame; (2) 
no visible emissions except for a total of 5 minutes in a 2-hour 
period; (3) minimum net heating value of gas sent to the flare; and 
(4) maximum flare tip velocity.
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    First, the EPA is proposing to require all flares and enclosed 
combustion devices \213\ to have a continuous pilot flame and install a 
continuous parameter monitoring system capable of continuously (at 
least once every 5 minutes) monitoring for the presence of a pilot or 
combustion flame. This is in keeping with the requirements of the 
General Provisions to require a continuous pilot flame. The EPA is 
specifying more frequent monitoring intervals for the pilot light than 
for other continuous parameter monitoring systems (which require a 
minimum of one reading per hour) because the destruction efficiency 
will rapidly fall to zero in the absence of a pilot or combustion 
flame. Therefore, we determined that more frequent readings were needed 
for the pilot flame monitoring system to ensure the flare or enclosed 
combustion device achieves 95 percent destruction efficiency at all 
times.
---------------------------------------------------------------------------

    \213\ This discussion in the rest of this section applies to 
those enclosed combustion devices for which temperature is not 
correlated with destruction efficiency.
---------------------------------------------------------------------------

    Second, the EPA is proposing to require inspections to monitor for 
visible emissions using section 11 of EPA Method 22 of appendix A-7 of 
part 60 (EPA Method 22). The observation period for the EPA Method 22 
inspection would be 15 minutes. Visible emissions longer than 1 minute 
during the 15-minute period would be a deviation of the standard. This 
is consistent with similar requirements in NSPS OOOOa. The EPA is 
proposing that these inspections would occur monthly, and at other 
times as requested by the Administrator. For example, if the 
Administrator observed a flare with intermittent visible emissions, the 
Administrator may require the owner or operator to conduct an EPA 
Method 22 inspection to determine whether the flare is exceeding the 
visible emissions limit.
    Next, the EPA is proposing that flares and enclosed combustion 
devices monitor the net heating value of the vent gas sent to the flare 
or combustor. Owners and operators would install a continuous parameter 
monitoring system, such as a calorimeter, to continuously determine the 
net heating value of the gas sent to the flare or combustor. 
Alternatively, the owner or operator could conduct an initial 
assessment to demonstrate that the net heating value of the vent gas 
sent to the flare or combustor consistently exceeds the required 
minimum net heating value in 40 CFR 60.18 or the minimum net heating 
value proposed for pressure-assisted flares.\214\ The proposed initial 
demonstration consists of hourly monitoring over 10 days. The EPA is 
proposing this frequency and duration of monitoring in order to provide 
a large sampling set by which to assess the variability of the vent gas 
sent to the combustion device and to adequately characterize the tails 
of the distribution. When actively controlling net heating value, 
operators will generally control at a set point 10 to 20 percent higher 
than the limit to ensure they are meeting the limit at all times. 
Therefore, the EPA concluded that a 20 percent cushion was a reasonable 
minimum value for ``well above the threshold.'' To be considered 
consistently above the net heating value threshold, greater than 90 
percent of the measurements would need to be ``well above the 
threshold,'' with no readings below the threshold. Based on these 
considerations, the EPA

[[Page 74796]]

is proposing that if there are no hourly gas samples with a net heating 
value below the required minimum net heating value and 20 or fewer 
hourly gas samples are less than 1.2 times the required minimum net 
heating value, then the gas stream is considered to be ``consistently 
above the threshold'' and on-going continuous monitoring is not 
required.
---------------------------------------------------------------------------

    \214\ Pressure-assisted devices are not required to comply with 
the vent gas net heating value in 40 CFR 60.18. The EPA is proposing 
alternative net heating value requirements for these devices as 
discussed in detail below.
---------------------------------------------------------------------------

    Lastly, to ensure compliance with the maximum flare tip velocity 
requirement in 40 CFR 60.18, for flares and enclosed combustion 
devices, the EPA is proposing to require installation of a continuous 
parameter monitoring system to determine the flow of gas sent to the 
flare or combustor, except as noted below for pressure-assisted 
devices. Alternatively, the owner or operator may conduct an initial 
engineering assessment of the sources vented to the flare to 
demonstrate that, based on the maximum pressure of these sources, the 
maximum possible gas flow rate would not exceed the allowed maximum 
flare tip velocity in 40 CFR 60.18 or the maximum design flow rate of 
the enclosed combustor.
    The EPA has also determined that combustion devices may be 
operating at gas flow rates that are too low to support efficient 
combustion, resulting in uncombusted vented emissions. To address this 
issue, the EPA is proposing to require that manufacturers establish 
both a minimum and maximum flow rate during the testing performed under 
40 CFR 60.5413b(d) and 40 CFR 60.5413c(d) to ensure these devices 
operate efficiently in the field. Combustion control devices previously 
tested by the manufacturer for which the manufacturer was able to 
demonstrate the control device meets the performance requirements would 
not need to perform new performance tests. The zero-level at which the 
combustion control device was tested will be extracted from the 
previously submitted performance test report and added to the 
information on the EPA's website.\215\ For flares and enclosed 
combustion devices not tested by the manufacturer under 40 CFR 
60.5413b(d) or 40 CFR 60.5413c(d), the owner or operator would be 
required to establish a minimum vent gas flow rate based on 
manufacturer recommendations. Owners and operators would be required to 
continuously monitor the vent gas flow rate to ensure that it is above 
this minimum level whenever vent gas is sent to the flare or enclosed 
combustion device. As an option, the owner or operator could install a 
backpressure preventer which is set to operate at or above the minimum 
inlet gas flow rate. The EPA is soliciting comment on this additional 
requirement and whether there are additional situations where 
continuous monitoring of the vent gas flow rate is unnecessary.
---------------------------------------------------------------------------

    \215\ Information on combustion control devices tested by the 
manufacturer can be found at: https://www.epa.gov/stationary-sources-air-pollution/performance-testing-combustion-control-devices-manufacturers.
---------------------------------------------------------------------------

    For pressure-assisted devices, the EPA is proposing to include 
special provisions in NSPS OOOOb/EG OOOOc, which include a minimum net 
heating value (NHV) of the gas sent to the flare/combustor of 800 
British thermal units per standard cubic feet (Btu/scf) and an 
exemption from the maximum velocity requirements in 40 CFR 60.18.\216\ 
Pressure-assisted devices are designed to operate at high flare or 
burner tip velocities and use this velocity to improve mixing of the 
flared gas with surrounding air. For good combustion efficiency at 
these high velocities, the flared gas must have higher heat content 
than a non-pressure-assisted flare. The EPA evaluated pressure-assisted 
flares and determined that these flares must have flare gas with an NHV 
of 800 Btu/scf or higher to work efficiently.217 218 Also, 
because the burners are specifically designed to have high flow rates, 
the burner tip velocity typically exceeds the maximum flare tip 
velocity limit in 40 CFR 60.18. The maximum velocity limits in 40 CFR 
60.18 were set to prevent flame ``lift off'' or flame instability from 
conventional flare tips. However, pressure-assisted flare tips are 
specifically designed to operate efficiently at much higher velocities. 
The EPA found that pressure assisted flares can operate efficiently at 
these higher velocities. Therefore, the EPA is proposing that pressure-
assisted devices would not be subject to the maximum flare tip velocity 
limit.
---------------------------------------------------------------------------

    \216\ Pressure-assisted devices would still be subject to the 
requirements for a continuous pilot flame and the visible emissions 
requirement, as well as the requirement to continuously monitor (or 
perform an assessment) on the NHV of the vent gas.
    \217\ ``Notice of Final Approval for the Operation of a 
Pressure-Assisted Multi-Point Ground Flare at Occidental Chemical 
Corporation,'' 81 FR 23480, April 21, 2016, and ``Notice of Final 
Approval for an Alternative Means of Emission Limitation at 
ExxonMobil Corporation; Marathon Petroleum Company, LP (for Itself 
and on Behalf of Its Subsidiary, Blanchard Refining, LLC); Chalmette 
Refining, LLC; and LACC, LLC,'' 83 FR 46939, September 17, 2018.
    \218\ Because pressure-assisted flares generally do not use 
assist gas, combustion zone NHV is the same as the flare gas NHV.
---------------------------------------------------------------------------

    Finally, the EPA is proposing operating requirements at 40 CFR 
60.5417b(f) (and 40 CFR 60.5417c(f)) and specifying what constitutes a 
deviation at 40 CFR 60.5417b(g) (and 40 CFR 60.5417c(g)) that are 
consistent with the operating and monitoring requirements outlined in 
this section and that are consistent across all affected facilities 
using control devices. Further, these sections are referenced in the 
recordkeeping and reporting requirements for each affected facility so 
that the reporting requirements for affected facilities that use 
control devices to comply with the standard have consistent control 
device reporting requirements regardless of the type of affected 
facility. The EPA is soliciting comment on all proposed requirements 
for control devices described within this section.

I. Reciprocating Compressors

    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, which is 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.
1. NSPS OOOOb
a. November 2021 Proposal
    Based on the analysis presented in section XII.E.1 of the November 
2021 proposal preamble (86 FR 63214-63220; November 15, 2021), the 
proposed BSER for NSPS OOOOb for reducing GHGs and VOC from new 
reciprocating compressors was the replacement of the rod packing based 
on an annual monitoring threshold. Under the November 2021 proposal, 
the owner or operator of a reciprocating compressor affected facility 
would have been required to monitor the rod packing emissions annually 
by conducting flow rate measurements. When the measured flow rate 
exceeded 2 scfm (in pressurized mode), replacement of the rod packing 
would have been required. As indicated at proposal, 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.\219\ Alternatively, the November 
2021 proposal would have

[[Page 74797]]

also provided owners and operators the option of routing rod packing 
emissions to a process via a CVS under negative pressure in order to 
comply with the rule. The proposed option to route to a process is 
allowed as an alternative under NSPS OOOOa because implementing this 
option, where feasible, would achieve greater emission reductions than 
the primary fixed schedule rod packing replacement BSER requirement 
under NSPS OOOOa.
---------------------------------------------------------------------------

    \219\ 86 FR 63218 (November 15, 2021).
---------------------------------------------------------------------------

b. Changes From November 2021 Proposal
    The BSER analysis is unchanged from what was presented in the 
November 2021 proposal (see 86 FR 63214-63220, section XII.E. 
Reciprocating Compressors). The EPA is proposing changes and specific 
clarifications to the November 2021 proposal standards for NSPS OOOOb. 
For the proposed replacement of the rod packing based on an emission 
limit and annual measurement requirement, we are proposing: (1) To 
clarify that the standard of performance is a numeric standard (not a 
work practice standard) of 2 scfm, (2) to allow for repair (in addition 
to replacement) of the rod packing in order to maintain an emission 
rate at or below 2 scfm; (3) to allow for monitoring based on 8,760 
hours of operation instead of based on a calendar year. We are also 
proposing regulatory text that clearly defines the required flow rate 
measurement methods and/or procedures, repair and replacement 
requirements, and recordkeeping and reporting requirements. For the 
alternative option of routing rod packing emissions to a process via a 
CVS under negative pressure, we are proposing to remove the negative 
pressure requirement. These changes take into account comments received 
on the November 2021 proposal, as explained below.
    The basis for the proposed changes and clarifications to the 
replacement of the rod packing based on a flow rate monitoring 
measurement for reciprocating compressors is presented in section 
IV.I.1.b.i of this preamble. The basis for the proposed change to the 
alternative option of routing rod packing emissions to a process via a 
CVS under negative pressure is presented in section IV.I.1.b.ii of this 
preamble. A summary of the proposed reciprocating compressor standards 
is presented in section IV.I.1.b.iii of this preamble.
i. Numerical Emission Limit Standard Proposed Changes
    Changes to Format of the Standard. In re-considering the BSER 
determination and standards for reciprocating compressors proposed in 
November 2021, the EPA recognized that it is feasible to prescribe a 
standard of performance, rather than a work practice standard,\220\ for 
reciprocating compressors. Accordingly, the EPA is now proposing a 
numerical emission limit requirement. The major difference between this 
standard and what the EPA proposed in November 2021 is that under this 
supplemental proposal, owners and operators would be required to 
maintain emissions at or below the emission limit (emission flow rate 
of 2 scfm) whereas under the November proposal, owners or operators 
would have been required to change out the rod packing only after 
discovering an exceedance of 2 scfm. The BSER is replacement of the rod 
packing and/or other necessary repair and maintenance activities to 
maintain emissions at or below 2 scfm.
---------------------------------------------------------------------------

    \220\ Under CAA section 111(h)(1), work practice standards are 
appropriate only where ``it is not feasible to prescribe or enforce 
a standard of performance.'' CAA section 111(h)(2) defines such 
infeasibility as ``any situation in which the Administrator 
determines that (A) a pollutant or pollutants cannot be emitted 
through a conveyance designed and constructed to emit or capture 
such pollutant, or that any requirement for, or use of, such a 
conveyance would be inconsistent with any Federal, state, or local 
law, or (B) the application of measurement methodology to a 
particular class of sources is not practicable due to technological 
or economic limitations.''
---------------------------------------------------------------------------

    Repair or Replacement. Commenters on the November 2021 proposal 
urged the EPA to allow for repair as an alternative to complete 
replacement of rod packing. The commenters pointed out that allowing 
repair would be consistent with California's reciprocating compressor 
rule requirements. See 17 California Code of Regulation section 
95668(c)(3)(D).\221\ One commenter noted that, for older units, 
replacing the rod packing does not always address emissions levels, as 
other maintenance issues can contribute to cylinder emissions, such as 
issues with the rod itself. The commenter added that providing the 
flexibility to repair as well as replace the rod packing could 
significantly impact personnel costs--while rod packing replacement on 
older units can require approximately 32-man hours per cylinder, a 
repair may entail a significantly lower level of effort and hours of 
labor.\222\
---------------------------------------------------------------------------

    \221\ Final Regulation Order. California Code of Regulations, 
Title 17, Division 3, Chapter 1, Subchapter 10 Climate Change, 
Article 4. Subarticle 13: Greenhouse Gas Emission Standards for 
Crude Oil and Natural Gas Facilities.
    \222\ See Document ID No. EPA-HQ-OAR-2021-0317-0817.
---------------------------------------------------------------------------

    The EPA agrees with the commenters' suggestion. The intent of the 
proposed reciprocating compressor standard was to require that the 
volumetric flow rate be maintained at or below 2 scfm. If repair can 
maintain the volumetric flowrate at or below 2 scfm without the need to 
replace the rod packing, the intent of the proposed standards would be 
met. Thus, under the proposed numerical emission limit, an owner or 
operator would be allowed to repair or replace the rod packing in order 
to maintain the volumetric flow rate at or below the 2 scfm emission 
limit.
    Hours of Operation Versus Calendar Year. Commenters \223\ on the 
November 2021 proposal recommended that the EPA consider requiring flow 
rate monitoring based on a compressor's hours of operation totaling one 
year (i.e., 8,760 hours) in lieu of requiring annual flow rate 
measurements based on a calendar year. Commenters stated that using the 
compressor's hours of operation would ensure that undue burden is not 
placed on owners and operators where compressors are not operational 
for multiple months or are used intermittently. The commenters 
explained that basing flow rate measurement requirements on a 
reciprocating compressor's hours of operation would allow owners and 
operators to stagger maintenance activity throughout the year. The 
comments further suggested that the EPA consider exemptions from the 
rule for limited-use reciprocating compressors and changing the flow 
rate measurement monitoring requirement frequency to every 2 years.
---------------------------------------------------------------------------

    \223\ See Document ID No. EPA-HQ-OAR-2021-0317-0415.
---------------------------------------------------------------------------

    In order to address limited-use reciprocating compressors and to 
allow owners and operators flexibility when planning maintenance, the 
EPA agrees that it makes sense to require periodic reciprocating 
compressor flow rate monitoring based on the hours of operation (i.e., 
8,760 hours) in lieu of requiring monitoring based on a calendar year. 
Thus, we are proposing to allow for periodic flow rate monitoring based 
on 8,760 hours of operation instead of requiring monitoring on a 
calendar year basis.
    Regulation Clarifications. Several commenters \224\ requested that 
the EPA clearly state in the rule that the GHGRP subpart W methods be 
allowed for the flow rate measurements. These commenters also requested 
that the EPA clearly state the proposed reciprocating compressor annual 
monitoring threshold and the repair and rod packing replacement 
requirements. Specifically, they sought certainty

[[Page 74798]]

regarding the schedule for repair and ``delay of repair'' criteria to 
ensure unnecessary restrictions are not placed on repair schedules, and 
a clear explanation of operating requirements for measurement (i.e., 
when the unit is operating).
---------------------------------------------------------------------------

    \224\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0415, and EPA-
HQ-OAR-2021-0317-1375.
---------------------------------------------------------------------------

    The EPA considered the commenters' specific requests for clarity 
within the requirements when developing the proposed regulatory text 
and the desire to be consistent with the GHGRP subpart W. We recognize 
this desire however we are concerned the flow rate measurements methods 
under GHGRP subpart W are not as well-defined or prescriptive as the 
methods the EPA requires for demonstrating compliance with an emission 
standard. Instead, the EPA is proposing the use of volumetric flow rate 
which meet the requirements of Method 2D (40 CFR part 60, appendix A) 
for testing emissions from reciprocating compressor rod packing and the 
use of a high-volume sampler to measure the emissions from proposing 
either the reciprocating compressor rod packing or centrifugal 
compressor seal vents (dry seals for NSPS OOOOb and all centrifugal 
compressor wet and dry seals for EG OOOOc).\225\ For the high-volume 
sampler, instead of relying on manufacturer defined procedures required 
in GHGRP Subpart W, the EPA is proposing a defined set of procedures 
and performance objectives to ensure consistent application of these 
samplers. In an effort to allow for additional innovation for these 
types of measurements, the EPA is also proposing to allow other 
methods, subject to Administrator approval, that have been validated 
according to Method 301 (40 CFR part 63, appendix A). The EPA solicits 
comment on the use of the proposed performance test methods and 
solicits comment on other methodologies that could be used to 
demonstrate compliance with the centrifugal compressor dry seal vent, 
centrifugal compressors for EG OOOOc, and reciprocating compressor rod 
packing emission standards.
---------------------------------------------------------------------------

    \225\ See section IV.G. for discussion on centrifugal 
compressors.
---------------------------------------------------------------------------

    The proposed NSPS OOOOb regulatory text also specifies that flow 
rate monitoring be conducted in operating or standby pressurized mode, 
and ``repair'' and ``delay of repair'' schedules, in addition to other 
clarifying requirements. The EPA is proposing to require conducting 
flow rate measurements during operating or standby pressurized mode 
because the measured emissions would be representative of actual 
emissions during operations. Repair schedules are proposed to require 
repair of equipment in a timely manner to mitigate emissions. Delay of 
repair would be allowed when owners and operators required more time to 
repair equipment based on scenarios beyond the owner or operator's 
control (e.g., issues with availability of equipment or where repair 
necessitates a compressor shutdown when redundancy of compressors is 
not available).
ii. Routing Emissions to a Process Via a Closed Vent System Under 
Negative Pressure
    The EPA received comments on the November 2021 proposal related to 
its proposed compliance alternative of routing rod packing emissions to 
a process via a CVS under negative pressure. One commenter \226\ noted 
that routing emissions to a process should not require negative 
pressure, stating that some pressure differential is required to take 
gas out of the rod packing vent and into the desired location. This 
commenter further stated that the use of negative pressure can raise 
safety and operational issues, and that operating a crankcase 
collection system under negative pressure (i.e., in a vacuum) creates 
the possibility of introducing oxygen into the system. This commenter 
added that allowing for pressure differential without requiring 
operation under negative pressure could lead to larger emission 
reductions overall, and that the proposed negative pressure requirement 
eliminates the ability to use technologies that could reduce emissions 
further. Another commenter \227\ similarly reported that the use of 
negative pressure presents safety concerns of creating an explosive 
mixture of natural gas and atmospheric air, should there be any leak 
between the negative pressure source and the packing vent. The 
commenter stated that as long as the packing vent recovery system is at 
a lower pressure; the packing vent gas will be recovered without 
leaking to atmosphere and there will be no risk of introducing 
atmospheric air to the natural gas.
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    \226\ See Document ID No. EPA-HQ-OAR-2021-0317-0817.
    \227\ See Document ID No. EPA-HQ-OAR-2021-0317-0745.
---------------------------------------------------------------------------

    The November 2021 proposal included the requirement to route rod 
packing emissions to a process via a CVS under negative pressure based 
on information submitted by a petitioner \228\ on NSPS OOOO that 
requested/suggested an alternative standard that would result in equal 
to or greater emissions reductions than the rod packing replacement 
standard. The petitioner's suggested alternative standard was to 
capture emissions under negative pressure, thus allowing all emissions 
to be routed to the engine. The petitioner suggested achieving this by 
recovering vented emissions from the rod packing under negative 
pressure and routing these emissions of otherwise vented gas to the air 
intake of a reciprocating internal combustion engine that would burn 
the gas as fuel to augment the normal fuel supply. The petitioner 
reasoned that emission reductions would be commensurate with, or better 
than, the reductions from the rod packing replacement standard. The EPA 
acknowledged at the time (2014) that this technology may not be 
applicable or feasible for every compressor installation and situation. 
However, the EPA proposed this option as an alternative to the rod 
packing replacement standards for those instances where it could be 
applied.\229\
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    \228\ Letter from Veronica Nasser, REM Technologies, Inc., to 
Lisa P. Jackson, EPA Administrator, Petition for Reconsideration.
    \229\ See 79 FR 41760-41761 (July 17, 2014).
---------------------------------------------------------------------------

    In light of the comments received on the November 2021 proposal, 
and an increased understanding of this type of approach, the EPA is 
proposing to revise the compliance alternative by continuing to allow 
emissions to be routed to a process via a CVS but removing the 
requirement for this to occur under negative pressure. The intent of 
requiring ``negative pressure'' was that there be sufficient pressure 
differential such that emissions would be routed from the compressor 
via the CVS to the process. The EPA did not intend to create a safety 
issue or limit technologies that would achieve equivalent or greater 
emission reductions than the work practice standard. Since such a 
pressure differential would be created when the reciprocating 
compressor is operating, specifying that emissions need to be routed to 
a process via a CVS under negative pressure is unnecessary. As the 
commenter noted, this is already understood for other sources where the 
standards require routing of emissions through a CVS to a process or 
control device.
    As noted above, routing emissions to a process is an existing 
compliance option under NSPS OOOO and NSPS OOOOa and the EPA has 
assumed that the emissions reduced by this option, where feasible to 
implement, are greater than those achieved by the proposed BSER 
requirement to implement maintenance and repair activities to maintain 
the flow rate (as a surrogate for emissions) from the reciprocating 
compressor rod packing at or below 2

[[Page 74799]]

scfm. The EPA solicits comment on its assumption that the emissions 
reduced by requiring the capture of gas and routing to a process are 
greater than the requirement to maintain the flow rate from the 
reciprocating compressor rod packing at or below 2 scfm. The EPA also 
is soliciting comment on the prevalence of owners and operators 
complying with NSPS OOOO and NSPS OOOOa by capturing and routing 
emissions from the reciprocating compressor rod packing to a process.
iii. Summary of Proposed Standards
    Affected Facility. The EPA is proposing to define a reciprocating 
compressor affected facility as each reciprocating compressor, which is 
a single reciprocating compressor. A reciprocating compressor located 
at a well site is not an affected facility under this subpart. A 
reciprocating compressor located at a centralized production facility 
is an affected facility under this subpart.
    Numerical Emission Limit Standards. The proposed NSPS OOOOb 
standard of performance for reciprocating compressor affected 
facilities is a numerical emission limit of 2 scfm (in operating or 
standby pressurized mode). The volumetric flow rate measurement from 
each reciprocating rod packing must be maintained to be less than or 
equal to a flow rate of 2 scfm (in operating or standby pressurized 
mode). The proposed BSER is to repair or replace the rod packing and to 
conduct other necessary repair and maintenance in order to maintain the 
emission rate at or below 2 scfm. The proposed monitoring requirements 
are to conduct volumetric flow rate measurements from each 
reciprocating compressor rod packing using the proposed monitoring 
methods in 40 CFR 60.5386b (which includes similar screening and flow 
rate measurement methods as required under GHGRP subpart W).
    The EPA is proposing to require the first volumetric flow rate 
measurements from a reciprocating compressor affected facility on or 
before 8,760 hours of operation. Subsequent volumetric emissions 
measurements from a reciprocating compressor affected facility would be 
required on or before 8,760 hours of operation after the previous 
measurement, or on or before 8,760 hours of operation after the date of 
the most recent reciprocating compressor rod packing replacement, 
whichever is later. Preventative maintenance or other corrective 
actions may be necessary (in addition to monitoring every 8,760 hours 
of operation) in order for owners or operators to ensure compliance at 
all times (consistent with the general duty clause 40 CFR 60.5470b(b)) 
with the required flow rate of 2 scfm or less).
    Routing Emissions From the Rod Packing to a Process. Alternatively, 
an owner or operator may choose to comply with NSPS OOOOb by routing 
emissions from the rod packing to a process through a CVS. This option 
would achieve greater than or equal to the 2 scfm numerical limit as 
emissions would be routed to a process via a closed system which would 
limit emissions from the rod packing from being vented to the 
atmosphere. An owner or operator must ensure that the CVS is designed 
to capture and route all gases, vapors, and fumes to a process (40 CFR 
60.5411b(a) and (c)). Additionally, an owner or operator would be 
required to design and operate the CVS with no detectable emissions and 
would be subject to bypass requirements (as applicable). Initial, 
monthly, and annual inspections (using OGI, EPA Method 21, or AVO (for 
monthly inspections only)) would be required to check for defects and 
detectable emissions.
    Recordkeeping and Reporting Requirements. Owners or operators 
complying with the numerical emission limit must track and report in 
their annual report the cumulative number of hours of operation of each 
reciprocating compressor since startup, since the previous screening/
volumetric flow rate emissions measurement, or since the previous 
reciprocating compressor repair/replacement of rod packing, as 
applicable. Their annual report must also include a description of the 
method used and the results of the volumetric flow rate measurement or 
emissions screening, as applicable. Lastly, owners or operators must 
maintain records and report each deviation from the emission limit 
standard that occurred during the reporting period, the date and time 
the deviation began, duration of the deviation and a description of the 
deviation.
    For a reciprocating compressor affected facility complying with the 
routing emissions from the rod packing to a process through a CVS, an 
owner or operator would be required to maintain records and report each 
reciprocating compressor that was constructed, modified, or 
reconstructed during the reporting period that is complying by using 
this option. In instances where a deviation from the standard has 
occurred during the reporting period, an owner or operator would be 
required to provide information on the date and time the deviation 
began, the duration of the deviation, and a description of the 
deviation. Additionally, they would be required to report of the dates 
of each cover and CVS inspection, whether defects or leaks are 
identified, and the date of repair or the date of anticipated repair if 
repair is delayed would be included in the annual report. Where bypass 
requirements apply, the date and time of each bypass alarm or each 
instance the key is checked out would be included in the annual report.
2. EG OOOOc
    Based on the analysis presented in section XII.E.2 of the November 
2021 proposal preamble (86 FR 63214-63220; November 15, 2021), the 
proposed BSER for EG OOOOc for reducing methane emissions from existing 
reciprocating compressors was the replacement of the rod packing based 
on an annual monitoring threshold. Under the November 2021 proposal, 
the owner or operator of a reciprocating compressor designated facility 
would have been required to monitor the rod packing emissions annually 
by conducting flow rate measurements. When the measured flow rate 
exceeded 2 scfm (in pressurized mode), replacement of the rod packing 
would have been required. Alternatively, the November 2021 proposal 
would have also provided owners and operators the compliance 
alternative of routing rod packing emissions to a process via a CVS 
under negative pressure to comply with the rule.
a. Standard Proposed Changes
    Based on the same public comment considerations and reasoning as 
explained above (see sections IV.I.1.b.i and ii of this preamble) for 
the proposed NSPS OOOOb reciprocating compressor rule changes, the EPA 
is proposing the same changes and requirements under EG OOOOc as 
presumptive standards for designated facilities.
b. Summary of Proposed Standards
    Designated Facility. The EPA is proposing to define a reciprocating 
compressor designated facility as each reciprocating compressor, which 
is a single reciprocating compressor. A reciprocating compressor 
located at a well site is not a designated facility under this subpart. 
A reciprocating compressor located at a centralized production facility 
is a designated facility under this subpart.
    Proposed Presumptive Standards. The proposed presumptive standards 
and BSER for existing reciprocating compressors are the same as those 
being proposed for new reciprocating compressors (see section 
IV.I.1.b.iii of this preamble). The requirements to

[[Page 74800]]

monitor the volumetric flow rate from a reciprocating compressor based 
on hours of operation, and to repair or replace the rod packing and to 
conduct any necessary repair and maintenance in order to maintain a 
flow rate at or below 2 scfm, would not result in any additional 
capital expenditures or retrofit considerations that would warrant 
different requirements. Alternatively, as with new sources, owners or 
operators of existing reciprocating compressors would be allowed to 
comply by routing rod packing emissions to a process via a CVS.

J. Storage Vessels

1. NSPS OOOOb
a. November 2021 Proposal
    Storage Vessel Affected Facility. In the November 2021 proposal, 
the EPA proposed to retain the current VOC standards for storage 
vessels (95 percent reduction) and proposed for the first-time 
standards for reducing methane emissions from storage vessels (95 
reduction). In addition, for both VOC and methane standards, the EPA 
proposed to define a storage vessel affected facility as a tank battery 
or a single storage vessel that is not part of a tank battery, with the 
potential for VOC emissions of 6 tpy or greater.\230\ The standards in 
NSPS OOOOa 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. See 76 
FR 52738, 52763 (August 23, 2011). Further, the 6 tpy applicability 
threshold was established by directly correlating the cost to control 
different levels of VOC emissions based on the use of a single vapor 
recovery or 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. Therefore, in the November 2021 proposal, the EPA proposed 
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. The EPA proposed that 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 in the tank battery. For new, modified, or 
reconstructed sources, the EPA proposed that 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. Additionally, the EPA proposed an emissions limit 
requiring 95 percent reduction as the BSER for reducing VOC and methane 
emissions from new, modified, or reconstructed storage vessel affected 
facilities. The EPA also requested comment on increasing combustion 
efficiency to 98 percent control and on requiring additional monitoring 
of the control device. See IV.G of this preamble for discussion related 
to combustion control devices.
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    \230\ For the reasons explained in the November 2021 proposal, 
the 6 tpy VOC applicability threshold would apply to both methane 
and VOC standards.
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    Modification. In the November 2021 proposal, the EPA proposed 
specific provisions to specify what circumstances constitute a 
modification of an existing storage vessel or tank battery, and thus 
subject it to the proposed NSPS OOOOb. The EPA proposed that a single 
storage vessel or tank battery is modified when certain physical or 
operational changes are made (86 FR 63178; November 15, 2021) to the 
single storage vessel or tank battery which result in an increase in 
the potential methane or VOC emissions. The EPA proposed that the owner 
or operator would be required to recalculate the potential VOC 
emissions when any of these actions occurred on an existing tank 
battery, to determine if a modification occurred. The EPA proposed that 
an existing tank battery would become subject to the proposed NSPS 
OOOOb if it is modified pursuant to this definition of modification and 
its potential VOC emissions exceeded the proposed 6 tpy VOC emissions 
threshold.
    Legally and Practicably Enforceable. The EPA proposed to clarify 
the term ``legally and practicably enforceable'' as it related to 
determining applicability of the storage vessel standards, The intent 
of this proposed definition (86 FR 63201; November 15, 2021) was to 
provide clarity to owners and operators claiming the storage vessel is 
not an affected facility in NSPS OOOOb, due to legally and practicably 
enforceable limits that limit their potential for VOC emissions below 6 
tpy.
b. Changes From November 2021 Proposal
    Storage Vessel Affected Facility. In this supplemental proposal, 
the EPA is proposing that a storage vessel affected facility is a tank 
battery which has the potential for VOC emissions equal to or greater 
than 6 tpy or the potential for methane emissions equal to or greater 
than 20 tpy. Specifically, the EPA is proposing to define a tank 
battery as a group of all storage vessels that are manifolded together 
for liquid transfer. A tank battery may consist of a single storage 
vessel if there is only one storage vessel is present, or the 
individual storage vessels at the site are not manifolded for liquid 
transfer. Commenters generally supported basing the potential for 
emissions on a tank battery instead of an individual storage vessel. 
The EPA received several comments that suggested changes to the 
definition of tank battery relating to how the tanks were manifolded 
and the proximity of tanks within the tank battery. Specifically, these 
commenters recommended that the definition of tank battery not include 
the term ``adjacent'' and should be based on tanks that are manifolded 
by liquid line.\231\ Commenters suggested these changes to avoid 
confusion around applicability and to align with existing state 
programs.\232\ The EPA agrees that these changes reflect our intent 
that a group of storage vessels which are manifolded together by liquid 
line operate as a system and, as such, share the same control, the cost 
of which was the basis for defining the applicability threshold; the 
total throughput to the tank battery is the basis for determining the 
potential for VOC and methane emissions for the tank battery, based on 
the maximum average daily throughput to the tank battery. This 
rationale holds regardless of the physical proximity to each other and 
therefore the term ``adjacent'' does not add additional clarity. Also, 
because tank batteries with the potential for VOC and methane emissions 
(greater than or equal to the thresholds) are: (1) Storage vessel 
affected facilities which require control; and (2) those standards 
require that all vapors from the tank battery are routed through a CVS 
(i.e., manifolded), it is not necessary to include the provision that 
vapor lines are manifolded in the definition of tank battery.
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    \231\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0810, EPA-HQ-
OAR-2021-0317-0814 and EPA-HQ-OAR-2021-0317-0831.
    \232\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0808 and EPA-HQ-
OAR-2021-0317-0831.
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    As stated above, the EPA is also proposing to include the 20 tpy

[[Page 74801]]

potential for methane emission threshold for determining applicability 
to NSPS OOOOb. As discussed in the November 2021 proposal, the EPA 
determined that it is cost-effective to reduce methane emissions by 95 
percent from existing tank batteries with potential methane emissions 
of 20 tpy. The EPA focused the November 2021 proposed NSPS OOOOb 
requirements on the 6 tpy VOC threshold because the EPA expects that 
most tank batteries will exceed the 6 tpy VOC threshold well before 
they exceed the 20 tpy methane threshold. However, based on our cost 
estimates, the EPA determined it is cost effective to control tank 
batteries if their methane emissions exceed 20 tpy, but the potential 
VOC emissions remain below 6 tpy. As such, in the unusual case that the 
methane threshold is triggered prior to the VOC threshold, the EPA 
determined it necessary to directly include the 20 tpy potential 
methane emissions threshold in the storage vessel affected facility 
definition.
    The EPA also is proposing that a ``generally accepted model or 
calculation methodology'' used to determine VOC and methane emissions 
must account for flashing, working, and breathing losses. As discussed 
in the November 2021 proposal, both methane and VOC emissions from 
storage vessels are a result of working, breathing, and flashing 
losses. 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. See 86 FR 63198 (November 15, 2021). 
For tank batteries with flashing losses, those emissions can dwarf 
working and breathing losses from the same tank battery. There are many 
``generally accepted'' models or calculation methodologies for 
estimating storage vessel emissions, but they do not all estimate flash 
emissions. Therefore, it is important to specify in the rule the EPA's 
requirement that emissions calculations account for such emissions when 
flash emissions occur.
    Additionally, the EPA is including in this supplemental proposal 
regulatory text which instructs the owner or operator on how to 
determine the potential for VOC or methane emissions as the cumulative 
emissions from all storage vessels within the tank battery according to 
certain timelines; for each tank battery located at a well site or 
centralized production facility the determination must occur 30 days 
after startup of production, or within 30 days after a physical or 
operational action which may trigger a modification or reconstruction; 
or for each tank battery located at a compressor station or onshore 
natural gas processing plan, the determination must occur prior to 
startup of the compressor station or onshore natural gas processing 
plant (or within 30 days after an action which may trigger 
reconstruction or modification). These timelines are consistent with 
the timelines provided in NSPS OOOOa for determining the potential for 
VOC emissions after startup of production (for a well site) or startup 
of the compressor station or onshore natural gas processing plant but 
are being proposed to also include timelines for centralized production 
facilities as well as timelines for determining the potential for VOC 
and methane emissions following an action which may trigger 
reconstruction or modification. The EPA believes this proposed 
regulatory text will provide direction and clarity to owners and 
operators for when the potential for VOC and methane emissions 
determinations must be made based on potentially triggering events. See 
the following discussion regarding reconstruction and modification.
    Reconstruction and Modification. The EPA is proposing the following 
changes from the November 2021 proposal related to definitions for 
reconstruction and modification for storage vessels. This proposal 
includes a definition of ``reconstruction'' as well as ``modification'' 
at 40 CFR 60.5365b(e)(3) for determining if an existing tank battery 
becomes a storage vessel affected facility subject to NSPS OOOOb. The 
proposed rule will apply to sources that are new, reconstructed, and 
modified sources after November 15, 2021. In the November 2021 proposal 
the EPA discussed our rationale for proposing specific actions which 
lead to an increase in VOC and methane emissions and therefore, 
constitute a modification of an existing tank battery. Generally, that 
rationale was to provide clarity on actions which are considered a 
modification of a tank battery. See 86 FR 63198 (November 15, 2021).
    In this proposed rule, the EPA is proposing two actions which 
constitute reconstruction: (1) Over half of the storage vessels are 
replaced in an existing tank battery that consists of more than one 
storage vessel; or (2) the provisions of 40 CFR 60.15 are met for the 
existing tank battery that consists of a single storage vessel. Section 
60.15 of the General Provisions to part 60 states that reconstruction 
occurs when the replacement of new components exceeds 50 percent of the 
capital cost that would be required to construct a comparable entirely 
new facility and it is technologically and economically feasible to 
meet the applicable standard under part 60. Reconstruction applies 
irrespective of any change in emissions rate. ``Fixed'' capital cost is 
further defined at 40 CFR 60.15(c) as the capital needed to provide all 
of the depreciable components and 40 CFR 60.15(g) allows for individual 
subparts to include specific provisions to refine or delimit the 
concept of reconstruction. Finally, 40 CFR 60.15(d) and (e) provide 
that the owner or operator must notify the Administrator prior to the 
proposed replacement with an estimate of the fixed capital cost of 
replacement (among other items, see 40 CFR 60.15(d)) and upon receipt, 
the Administrator will determine if the proposed replacement 
constitutes reconstruction.
    Based on our experience from NSPS OOOO and NSPS OOOOa, the 
predominant type of storage vessel expected to be covered by the 
proposed NSPS are fixed roof storage vessels, and as part of the 
storage vessel affected facility, have limited depreciable components 
beyond the storage vessel itself (e.g., thief hatches and pressure 
relief devices). Because the EPA expects that each affected facility 
will undertake similar fixed capital cost replacements at storage 
vessel affected facilities, namely replacing one or more storage 
vessels, replacing thief hatches, and replacing pressure relief 
devices, we believe that it will serve as a burden reduction to 
industry to establish uniform criteria which constitute reconstruction. 
For a tank battery which consists of a single storage vessel, it may be 
possible that the cost of replacing the thief hatch, pressure relief 
device or other depreciable components could exceed 50 percent of the 
cost of an entirely new storage vessel, therefore the EPA is proposing 
that the provisions of 40 CFR 60.15 would apply. The EPA requests 
comment on this assumption that the costs of replacement of all 
depreciable components on a single storage vessel could exceed 50 
percent of the cost of an entirely new storage vessel. For a tank 
battery which consists of more than a single storage vessel, we believe 
that the cost of replacing storage vessel components such as thief 
hatches and pressure relief devices, in comparison to the cost of 
constructing

[[Page 74802]]

an entirely new storage vessel affected facility, will not exceed 50 
percent of the cost of constructing a comparable new storage vessel 
affected facility. Therefore, the EPA is proposing to simplify and 
streamline the reconstruction determination for tank batteries by 
defining reconstruction at a tank battery with more than a single 
storage vessel as replacement of 50 percent of the storage vessels in 
the tank battery. This defined reconstruction action will eliminate the 
need for the owner or operator to submit the notification in 40 CFR 
60.15(d) and await the EPA's response under 40 CFR 60.15(e), before 
undertaking a replacement.
    An important factor in determining whether over 50 percent of the 
storage vessels in an existing tank battery has been replaced is the 
time period for making such assessment. Consider the following 
scenario: an owner replaces one-third of the storage vessels in an 
existing tank battery and, shortly thereafter, replaces another third 
of the storage vessels in that tank battery. The owner has replaced 60 
percent of the storage vessels in that tank battery in total; however, 
without specifying the time frame for assessing reconstruction, it is 
unclear whether the tank battery is ``reconstructed'' because over half 
of the storage vessels in the tank battery have been replaced, or the 
replacements are two separate programs and therefore should not be 
aggregated for purposes of determining reconstruction. For the reasons 
discussed in section IV.D and IV.E of this preamble, the EPA is 
proposing to interpret natural gas-drive pneumatic controller and 
pneumatic pump replacements to include all natural gas-driven pneumatic 
controllers and pneumatic pumps which commence replacement (but are not 
necessarily completed) within any 2-year period in determining whether 
the replacements constitute reconstruction. The EPA solicits comment on 
whether to similarly set a specific time period (or rolling time 
period) within which replaced storage vessels in an existing tank 
battery will be aggregated towards determining whether the 50 percent 
replacement threshold has been exceeded, and if so, whether a 2-year 
time frame or another time frame is appropriate for determining 
reconstruction to a tank battery with more than a single storage 
vessel.
    Related to modifications, the EPA explained in the November 2021 
proposal that actions occurring at a well site, such as refracturing a 
well or adding a new well that sends these liquids to the tank battery 
at the well site or centralized production facility, would result in an 
increase in VOC and methane emissions based on an increase in 
volumetric throughput to the tank battery. See 86 FR 63199 (November 
15, 2021). However, this does not always hold true for tank batteries 
located at a compressor stations or onshore natural gas processing 
plants. In the September 15, 2020, rule (see 85 FR 57404), the EPA 
finalized a different framework for determining the potential for VOC 
emissions from storage vessels located at compressor stations and 
onshore natural gas processing plants, based on comments received on 
the September 15, 2020, rule that storage vessels located at these 
types of facilities are designed to receive liquids from multiple well 
sites that may startup production over a longer period of time.\233\ To 
account for this future throughput to the storage vessels, compressor 
stations and natural gas processing plants use analysis based on the 
future maximum throughput capacity which is then used to obtain 
permits. Therefore, the EPA agrees that when a tank battery at a 
compressor station or onshore natural gas processing plant receives 
additional throughput which has already been accounted for in the 
design capacity of that tank battery and included as a legally and 
practically enforceable limit in a permit for the tank battery, that 
additional throughput does not result in an emission increase from the 
tank battery because those emissions have already been accounted for in 
the permit.
---------------------------------------------------------------------------

    \233\ See Document ID No. EPA-HQ-OAR-2017-0473-1261.
---------------------------------------------------------------------------

    In summary, the EPA is proposing that a modification occurs to an 
existing tank battery located at a well site or centralized production 
facility when the tank battery receives additional crude oil, 
condensate, intermediate hydrocarbons, or produced water throughput and 
the potential for VOC or methane emissions increases above the 
applicable thresholds. Separately, the EPA is proposing that a 
modification occurs to an existing tank battery located at a compressor 
station or onshore natural gas processing plant when the tank battery 
receives additional fluids which cumulatively exceed the throughput 
used in the most recent determination for VOC or methane missions 
(e.g., permit) based on the design capacity of such tank battery. In 
addition, as proposed in November 2021, modification is also triggered 
by the following two events: (1) A storage vessel is added to an 
existing tank battery; and/or (2) one or more storage vessels are 
replaced such that the cumulative storage capacity of the existing tank 
battery increases.
    One commenter expressed concerns that the change to a tank battery 
(in NSPS OOOOb) versus a single tank (in NSPS OOOOa) will cause 
confusion with the requirements of NSPS OOOOa because it creates a 
disconnect with how the previous NSPS for this source category applies 
the affected facility status to storage tanks. The commenter states 
that creating separate ``classifications'' within the NSPS based on 
dates of construction or modification will create additional burden 
when reviewing authorizations within the specified legislatively 
mandated time frames.\234\ The EPA discusses the interplay and 
effective dates between prior standards applicable to the Crude Oil and 
Natural Gas source category in sections III.B, III.C and III.D of this 
preamble. However, to address specific questions regarding 
applicability to storage vessels which may be subject to NSPS OOOO, 
NSPS OOOOa, or EG OOOOc, the EPA is providing a discussion of 
applicability for several anticipated scenarios which may be triggered 
by a potential modification action described above. For purposes of the 
scenarios below, the EPA is using the proposed definition of a tank 
battery, which includes a single storage vessel if only one storage 
vessel is present.
---------------------------------------------------------------------------

    \234\ See Document ID No. EPA-HQ-OAR-2021-0317-0763.
---------------------------------------------------------------------------

    Scenario One--An existing tank battery has the potential for 
methane emissions greater than or equal to 20 tpy methane, therefore it 
is a designated facility for purposes of EG OOOOc. Subsequently, one of 
the proposed physical or operational changes in NSPS OOOOb at 40 CFR 
60.5365b(e)(3)(ii) (i.e., adds a storage vessel to an existing tank 
battery; adds capacity to an existing tank battery; or receives 
additional fluids) occurs. In order to determine if modification has 
occurred to the existing tank battery, the owner or operator would 
calculate the potential for VOC and methane emissions in accordance 
with the proposed 40 CFR 60.5365b(e)(2). If the potential for either 
VOC or methane is above the proposed threshold, the tank battery is a 
modified storage vessel affected facility subject to NSPS OOOOb. If the 
potential for both VOC and methane is not above the threshold, the tank 
battery is not a modified (or reconstructed) storage vessel affected 
facility for purposes of NSPS OOOOb and remains a designated facility 
for purposes of EG OOOOc.

[[Page 74803]]

    Scenario Two--An existing tank battery is not a designated facility 
under EG OOOOc (i.e., the potential for methane emissions is less than 
20 tpy). Like scenario 1, subsequently, one of the proposed physical or 
operational changes in NSPS OOOOb occurs and the owner or operator 
calculates the potential for VOC and methane emissions. If the 
potential for either VOC or methane emissions is above the proposed 
threshold, the tank battery is a modified storage vessel affected 
facility subject to NSPS OOOOb. If the potential for both VOC and 
methane is not above the proposed threshold, the tank battery is not a 
modified storage vessel affected facility for the purposes of NSPS 
OOOOb and is also not a designated facility under EG OOOOc.
    Scenario Three--An existing storage vessel is a single storage 
vessel subject to either NSPS OOOO or NSPS OOOOa and is part of a tank 
battery. One of the proposed physical or operational changes in NSPS 
OOOOb occurs and the owner or operator calculates the potential for VOC 
and methane emissions from the entire tank battery. If the potential 
for either VOC or methane is above the threshold, the tank battery is a 
modified storage vessel affected facility subject to NSPS OOOOb, and 
the single storage vessel would continue to be subject to the 
applicable NSPS OOOO or NSPS OOOOa. However, where a facility is 
subject to multiple standards, the general practice is to streamline 
compliance by complying with the more stringent standard, which would 
in effect meet the less stringent standards. If the potential for both 
VOC and methane is not above the proposed threshold, the single storage 
vessel is not modified for the purposes of NSPS OOOOb and remains 
subject to NSPS OOOO or NSPS OOOOa.
    Scenario Four--An existing storage vessel is a single storage 
vessel and is subject to either NSPS OOOO or NSPS OOOOa. The single 
storage vessel is not a designated facility under EG OOOOc because the 
potential for methane emissions is less than 20 tpy. One of the 
proposed physical or operational changes in NSPS OOOOb occurs and the 
owner or operator calculates the potential for VOC and methane 
emissions from the single storage vessel. If the potential for either 
VOC or methane is above the proposed threshold, the single tank is a 
tank battery which is a modified storage vessel affected facility 
subject to NSPS OOOOb, as well as NSPS OOOO or NSPS OOOOa. Where a 
facility is subject to multiple standards, the general practice is to 
streamline compliance by complying with the more stringent standard, 
which would in effect meet the less stringent standards; however, 
streamlining may not be necessary here if the EPA finalized the 
proposed 95 percent reduction, which is the storage vessel standard in 
NSPS OOOO and NSPS OOOOa. If the potential for both VOC and methane is 
not above the threshold, the single tank is not modified for the 
purposes of NSPS OOOOb and remains subject to NSPS OOOO or NSPS OOOOa.
    Removed From Service. Finally, in NSPS OOOO and NSPS OOOOa, the EPA 
includes provisions to address the status of storage vessel affected 
facilities which are physically isolated and disconnected from the 
process for purposes other than maintenance, which is referred to as 
``removed from service''.\235\ Those regulations also include a 
framework for determining the affected facility status of such storage 
vessels when they are ``returned to service'', either by: (1) Being 
reconnected to the original source of liquids, (2) used to replace any 
storage vessel affected facility, or (3) installed in any location 
covered by the subpart and introduced with crude oil, condensate, 
intermediate hydrocarbon liquids or produced water. The EPA is 
including these same provisions in the proposed NSPS OOOOb for 
situations where there is more than one storage vessel in a tank 
battery and the entire tank battery is removed from or returned to 
service. Additionally, the EPA is proposing language to address 
situations when only a portion of the tank battery is removed from, or 
returned to, service. Specifically, the EPA is proposing to require 
complete emptying and degassing of the entire tank battery, or the 
portion of the tank battery that is being removed, for it to be 
considered ``removed from service''. Submission of a notification that 
these emptying and degassing requirements are met would also be 
required. Further, when a portion of a storage vessel affected facility 
is removed from service, in addition to the requirements above, the 
portion of the tank battery must be disconnected from the tank battery 
such that the portion is no longer manifolded to the tank battery by 
liquid or vapor transfer. When a tank battery is returned to service, 
it would retain the same applicability status that applied prior to 
removal from service. For tank batteries where only a portion of the 
tank battery is returned to service and it is reconnected to the 
original source of liquids, it remains a storage vessel affected 
facility subject to the same requirements that applied before being 
removed from service. If a storage vessel is used to replace a storage 
vessel affected facility, or portion of a storage vessel affected 
facility, or used to expand a storage vessel affected facility, it 
assumes the affected facility status of the storage vessel affected 
facility being replaced or expanded.
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    \235\ See 78 FR 58435 (September 23, 2013), 79 FR 79022 
(December 31, 2014), 80 FR 48262 (August 12, 2015), and 81 FR 35824 
(June 3, 2016).
---------------------------------------------------------------------------

    Request for Additional Comment. In addition to the proposed changes 
or clarifications described above, the EPA is soliciting comment on 
including a requirement to equip thief hatches with alarms, automated 
systems to monitor for pressure changes, or use of automatically 
closing thief hatches. Commenters noted that open thief hatches and 
deteriorated seals around tank openings are significant emissions 
sources at tank batteries. The EPA is aware that some owners and 
operators utilize automated systems to alert when pressure changes 
occur that could signal an open thief hatch. Additionally, where 
automated systems are not available, there are alarms that could be 
utilized to alert (via audible alarm or remote notification to the 
nearest field office) that an unseated thief hatch is present.\236\ The 
EPA is soliciting information on the costs, operation, and feasibility 
of installing these automated systems, alarms, or the use of 
automatically closing thief hatches.
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    \236\ See Document ID No. EPA-HQ-OAR-2021-0317-0814.
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c. Summary of Proposed Requirements
    In this proposed rule, owners and operators of storage vessel 
affected facilities must reduce methane and VOC emissions by 95 
percent. Consistent with provisions of NSPS OOOO and NSPS OOOOa, the 
proposed rule also includes the option where if the owner or operator 
maintains the uncontrolled actual VOC emissions at less than 4 tpy and 
the actual methane emissions at less than 14 tpy as determined monthly 
for 12 consecutive months, controls are no longer required. Storage 
vessel affected facilities which use a control device to reduce 
emissions must equip each storage vessel in the tank battery with a 
cover and manifold all storage vessels in the tank battery such that 
all vapors are shared among the headspaces of the storage vessel 
affected facility. The tank battery must be equipped with a CVS which 
routes all emissions to a control device. The proposed rule would 
require that when using a flare, the flare must meet the requirements 
in 40 CFR 60.18, which the EPA is proposing to strengthen by including 
additional

[[Page 74804]]

requirements (as discussed in section IV.H of this preamble), and that 
monitoring, recordkeeping, and reporting be conducted to ensure that 
the flare is constantly achieving the required 95 percent reduction. 
More information on the control device monitoring and compliance 
provisions is provided in section IV.G of this preamble; additionally, 
notifications made through the super-emitter response program could 
help identify potential violations as provided in section IV.C of this 
preamble. If the storage vessel affected facility does not have 
flashing emissions and is not located at a well site or centralized 
production site, the owner or operator may use an internal or external 
floating roof to reduce emissions.
    In each annual report, owners and operators would be required to 
identify each storage vessel affected facility that was constructed, 
modified, or reconstructed during the reporting period and must 
document the emission rates of both VOC and methane individually. The 
annual report must include deviations that occurred during the 
reporting period and information for control devices tested by the 
manufacturer or the date and results of the control device performance 
test for control devices not tested by the manufacturer. The report 
also must include the results of inspections of covers and CVS and the 
identification of storage vessel affected facilities (or portion of 
storage vessel affected facility) removed from service or returned to 
service. For storage vessel affected facilities which comply with the 
uncontrolled 4 tpy VOC limit or 14 tpy methane limit, the report must 
include changes which resulted in the source no longer complying with 
those limits and the dates that the source began to comply with the 95 
percent reduction standard.
    Required records include documentation of the methane and VOC 
emissions determination and methodology, records of deviations and 
duration, records for the number of consecutive days a skid-mounted or 
permanently mobile-mounted storage vessel is on the site, the latitude 
and longitude coordinates of each storage vessel affected facility, and 
records associated with a manufacturer tested control device. Required 
records also include records demonstrating continuous compliance 
including inlet gas flow rate, presence of pilot flame, operation with 
no visible emissions, maintenance and repair logs, manufacturer's 
operating instructions, and dates that each storage vessel affected 
facility (or portion of storage vessel affected facility) is removed 
from service or returned to service. For storage vessel affected 
facilities which comply with the uncontrolled 4 tpy VOC or 14 tpy 
methane limit, records of changes which resulted in the source no 
longer complying with those limits and the dates that the source began 
to comply with the 95 percent reduction standard, including records of 
the methane and VOC determination and methodology. All associated 
records that demonstrate proper design and operation of the CVS, cover 
and control device also must be maintained (see section IV.G and IV.J. 
of this preamble).
2. EG OOOOc
    The EPA is also proposing presumptive standards to reduce methane 
for existing storage vessel affected facilities in this action that 
remain unchanged from the November 2021 proposal and are similar to 
those proposed for NSPS OOOOb. Because the BSER for reducing VOC and 
methane emissions are the same, the proposed presumptive standard is to 
reduce methane emissions by 95 percent. Some commenters expressed that 
creating separate classifications (e.g., tank batteries vs single 
tanks) within the NSPS based on dates of construction or modification 
will create additional burden when reviewing authorizations within the 
specified legislatively mandated time frames. Another commenter 
requested that EPA clarify whether other individual storage vessels in 
an existing tank battery remain affected facilities under NSPS OOOO or 
NSPS OOOOa, as applicable, or become part of the modified tank battery 
under NSPS OOOOb.\237\ The EPA discusses the interplay and effective 
dates between prior standards applicable to the Crude Oil and Natural 
Gas source category in sections III.B, III.C and III.D of this preamble 
and provides example scenarios, which the EPA believes will provide 
guidance to regulators and the regulated community.
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    \237\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.
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K. Covers and Closed Vent Systems

1. NSPS OOOOb
a. November 2021 Proposal
    In the November 2021 proposal, the EPA proposed CVS requirements 
for certain affected facilities to ensure that emissions are captured 
and routed to a process or control device, dependent on the standard 
for the affected/designated facility. The affected/designated 
facilities for which the EPA proposed the use of a CVS were wells (oil 
wells when routing associated gas to a control device), storage 
vessels, centrifugal compressors (wet seal), reciprocating compressors, 
pneumatic pumps, and process unit equipment affected/designated 
facilities. Additionally, for storage vessels using a control device to 
reduce emissions and centrifugal compressors with wet seals using a 
degassing system, the EPA proposed the use of covers to form a 
continuous impermeable barrier over the entire surface area of the 
liquid in the storage vessel or the centrifugal compressor wet seal 
fluid degassing system. The cover requirements ensure that all 
emissions are captured from those emissions sources and routed through 
a CVS to a control device, or in the case of centrifugal compressors, 
to a control device or to a process. This section discusses the cover 
and CVS requirements for those affected/designated facilities that are 
located at well sites, centralized production facilities, and 
compressor stations. See the discussion on CVS in section IV.L of this 
preamble for covers and CVS located at natural gas processing plants.
    In the November 2021 proposal, the EPA proposed that covers and CVS 
must be designed and operated with no detectable emissions (NDE). 
Further, the EPA proposed that where a CVS is used to route emissions 
from an affected facility, the owner or operator would demonstrate 
there are no detectable emissions from the covers and CVS through OGI 
or EPA Method 21 monitoring conducted during the fugitive emissions 
survey. Where emissions are detected, the emissions would be considered 
a violation of the NDE standard and thus a deviation,\238\ and 
corrective actions to complete all necessary repairs as soon as 
practicable would be required. The EPA also solicited comment on 
whether to include the option to continue utilizing monthly AVO surveys 
as demonstrations of NDE from a CVS associated with a pneumatic pump 
but did not propose that option specifically. We stated that because we 
anticipated that CVS associated with pneumatic pumps would be located 
at well sites subject to fugitive emissions monitoring, the monthly AVO 
option was not necessary. However, we solicited comment on whether 
there are circumstances where a CVS associated with a pneumatic pump is 
located at a well site not otherwise subject to

[[Page 74805]]

fugitive emissions monitoring and where OGI (or EPA Method 21) would be 
an additional burden.
---------------------------------------------------------------------------

    \238\ A deviation includes any instance in which an affected 
source fails to meet any emission limit, operating limit, or work 
practice standard; a deviation suggests potential violation with the 
applicable performance standard.
---------------------------------------------------------------------------

b. Changes From November 2021 Proposal
    In this supplemental proposal, the EPA is proposing specific 
revisions to the requirements for CVS associated with the affected/
designated facilities located at well sites, centralized production 
facilities, and compressor stations in the proposed NSPS OOOOb and EG 
OOOOc. First, the EPA is proposing the same design and operational 
requirements for all CVS when routing emissions to a control device or 
when routing emissions to a process, regardless of which affected/
designated facility is using the CVS. These proposed standards would 
apply to wells (oil wells when routing associated gas to a control 
device), centrifugal compressor, reciprocating compressor, pneumatic 
controller, pneumatic pump, storage vessel, and process unit equipment 
affected/designated facilities. See section IV.L of this preamble for 
additional discussion related to process unit equipment affected/
designated facilities at onshore natural gas processing plants.
    For these affected/designated facilities, the EPA is proposing the 
capture and routing of emissions through a CVS to a control device or 
process as part of the BSER, or an alternative to the BSER for specific 
situations such as technical infeasibility to apply BSER. The EPA finds 
that the demonstration of continuous compliance for these CVS should 
include the same robust standards to ensure the CVS are designed and 
operated to capture and route all emissions to the control device 
regardless of which affected/designated facility is using the CVS. The 
proposed standards for CVS include upfront engineering (Professional 
Engineer or in-house engineer) design analysis and certifications, an 
emissions limit that requires design and operation with no identifiable 
emissions, initial and periodic inspections of the CVS, and continuous 
monitoring of CVS bypass systems (unless equipped with a seal or 
closure mechanism). Therefore, in this proposal, the EPA is 
standardizing the design and operational requirements for CVS, 
regardless of their location or use (route to a control device or route 
to a process).
    The EPA is proposing to change the design and operational 
requirements for CVS (except for those associated with self-contained 
pneumatic controllers) from operation with NDE to operation with no 
identifiable emissions. The proposed change of terminology is not 
intended to change the stringency of the CVS requirements, which 
require that each CVS capture and route all gases, vapors, and fumes to 
a control device or a process, but it will clarify the design and 
operational standards, and the obligations on the part of the owner or 
operator if a leak is detected from the CVS during the inspections to 
ensure compliance with the no identifiable emissions standard.
    Based on comments received on the November 2021 proposal, there 
appears to be confusion whether the proposed NDE standard would be an 
emissions limit or a work practice standard. For example, one commenter 
\239\ stated that as written, the NDE standard would be a work practice 
standard because ``[a]s with all other fugitive emissions components, 
detection of a leak (in this case, defined as detectable emissions) 
through routine LDAR monitoring triggers the obligation to repair the 
leak. If that repair is accomplished according to the specific 
requirements in the rule, then there is no violation because the work 
practice has been fully implemented.'' This interpretation of the 
standard is not correct. In fact, CVS must be designed and operated to 
route all gases, vapors, and fumes to a control device or to a process, 
which is defined as an emission limit of NDE. The corrective actions 
(in the form of the repair provisions) are provided to ensure that 
owners and operators bring the CVS back into compliance with the NDE 
emission limit as quickly as possible.
---------------------------------------------------------------------------

    \239\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.
---------------------------------------------------------------------------

    Past efforts in NSPS OOOO and NSPS OOOOa to apply an NDE standard 
as an emission limitation, while still allowing repair, delay of repair 
or exceptions for unsafe and difficult to inspect equipment, may appear 
to condone a ``grace period'' during which compliance with an emissions 
limit is not required. Because the NDE standard in NSPS OOOO and NSPS 
OOOOa was established as an emissions limit, operation in exceedance of 
that limit is a deviation,\240\ even if the repair provisions are 
followed.
---------------------------------------------------------------------------

    \240\ A deviation signals possible violation with the 
performance standard for an affected facility because compliance is 
no longer demonstrated due to such exceedance.
---------------------------------------------------------------------------

    Similarly, the EPA is proposing an emissions limit for covers and 
CVS in this supplemental proposal for NSPS OOOOb and EG OOOOc. However, 
NDE is a term closely linked with EPA Method 21, and is defined based 
on an instrument reading in units of ppmv. Because the EPA is proposing 
compliance inspections for covers and CVS using optical gas imaging and 
AVO, no instrument reading in ppmv is available. Therefore, the EPA is 
proposing the design and operational standard as an emissions limit of 
no identifiable emissions, which is more appropriate for the methods of 
detection required.
    To ensure compliance with the no identifiable emissions design and 
operational standard for covers and CVS located at well sites, 
centralized production facilities, and compressor stations, the EPA is 
proposing that owners or operators would conduct initial and quarterly 
OGI inspections (except for the Alaska North Slope which is annually). 
Any identified emissions would be a violation of this emissions limit 
and would be subject to repair with a first attempt completed within 5 
days and final repair within 30 days of identification. If the owner or 
operator is using the EPA Method 21 alternative for their fugitive 
emissions components, then any instrument reading greater than 500 ppmv 
above background is considered identified emissions, would be a 
potential violation of the no identifiable emissions standard, and 
would require repair within the same 5- and 30-day timeframe to bring 
the CVS back into compliance.
    The EPA is also proposing to require AVO inspections for CVS and 
covers located at well sites, centralized production facilities and 
compressor stations. The EPA is proposing that AVO inspections of CVS 
and covers must occur at the same frequency specified for fugitive 
emissions components affected facilities located at the same type of 
site. As discussed in section IV.A.1.a.ii of this preamble, the EPA is 
proposing that CVS and covers located at a well site, centralized 
production facility, or compressor station site, which are not 
associated with a well, centrifugal compressor, reciprocating 
compressor, pneumatic controller, pneumatic pump, or storage vessel 
affected facility, are fugitive emissions components and subject to 
those standards, which include periodic OGI (or EPA Method 21 as an 
alternative) and monthly or bimonthly AVO inspections. Because we are 
aligning the CVS associated with well, centrifugal compressor, 
reciprocating compressor, pneumatic controller, pneumatic pump, or 
storage vessel affected facilities inspections with the frequency of 
inspections under the fugitives program, there should be no additional 
cost associated with conducting these AVO inspections of CVS that are 
not fugitive emissions

[[Page 74806]]

components at the same time and at the same place, and we believe that 
identifying and repairing such leaks is consistent with the proposed 
requirement at 40 CFR 60.5370b(b) in a manner consistent with good air 
pollution control practice for minimizing emissions. See section IV.A 
of this preamble for a full discussion of the fugitive emissions 
requirements.
    The EPA did not receive comment in response to our request 
regarding the burden of OGI (or EPA Method 21) monitoring for CVS 
associated with pneumatic pumps at well sites. Therefore, the EPA is 
not proposing separate standards for those CVS associated with 
pneumatic pumps and is proposing consistent standards for all CVS 
associated with affected/designated facilities under NSPS OOOOb or EG 
OOOOc.
    As discussed in section IV.D of this preamble, the EPA is proposing 
that pneumatic controllers may comply with the zero-emission methane 
and VOC standard for pneumatic controllers by installing a self-
contained pneumatic controller, which is a natural gas-driven 
controller designed so that there are no emissions to the atmosphere. 
These controllers are designated as ``no identifiable emissions'' in 
the proposed rule. Because these are designed to contain all gases, 
vapors, or fumes from the controller, the EPA finds it appropriate to 
apply the same continuous compliance requirements to self-contained 
controllers as those for covers and CVS described in this section. That 
is, the EPA is proposing to require the operation of self-contained 
pneumatic controllers with no identifiable emissions, as demonstrated 
through quarterly OGI monitoring. Any emissions identified would be a 
violation of the zero emissions standard. The repair requirements 
described for CVS would also apply to bring the self-contained 
pneumatic controller back into compliance with the zero emissions 
standard.
    As discussed in section IV.B of this preamble, the EPA also is 
proposing provisions for the use of alternative test methods that 
employ alternative periodic screening technologies or continuous 
monitoring systems. The EPA is proposing to allow use of alternative 
test methods to replace the use of OGI for demonstrating continuous 
compliance of the no identifiable emissions standard for covers and 
CVS. The EPA recognizes that the allowable minimum detection thresholds 
of the screening technologies used in the alternative periodic 
screening approach may not be capable of identifying all of the 
potential emissions from these sources; however we find that well 
designed, maintained, and certified covers and CVS systems are not 
prone to leaks, and the majority of emission events from these systems 
can be attributed to short-term operational events or malfunctions that 
would be at a level easily identified by screening technology meeting 
the allowable minimum detection thresholds. The EPA considers the use 
of more frequent surveys (monthly to quarterly) using approved 
screening technologies and either annual (if required based on minimum 
detection threshold and frequency) or OGI surveys resulting from 
emissions detected during screening would ensure equivalent compliance 
assurance of the no identifiable emissions standard as the quarterly 
OGI surveys paired with monthly or bimonthly AVO inspections. The EPA 
solicits comments on the use of the alternative periodic screening 
approach as an alternative compliance assurance for covers and CVS 
associated with affected/designated facilities, and we solicit comments 
that the minimum detection thresholds summarized in Tables 20 and 21 
(section IV.B of this preamble) are suitable for this purpose.
c. Summary of Proposed Requirements
    The EPA is proposing standards which apply to CVS at a well, 
centrifugal compressor, reciprocating compressor, pneumatic controller, 
pneumatic pump, storage vessel, or process unit equipment affected/
designated facility. The EPA also is proposing standards for covers at 
a centrifugal compressor and storage vessel affected/designated 
facility. This summary is limited to covers and CVS located at well 
sites, centralized production facilities, and compressor stations. 
Covers and CVS located at natural gas processing plants (process unit 
equipment affected/designated facilities) are discussed in section IV.L 
of this preamble.
    Each CVS must be designed and operated to capture and route all 
gases, vapors, and fumes to a process or to a control device and comply 
with an emissions limit of no identifiable emissions. Initial and 
continuous compliance of the no identifiable emissions standard would 
be demonstrated through OGI monitoring and AVO inspections conducted at 
the same frequency as the fugitive emissions monitoring for the type of 
site. Specifically, for the well sites and centralized production 
facilities where a CVS is present, quarterly OGI and bimonthly AVO 
would be required; for compressor stations, quarterly OGI and monthly 
AVO would be required. If the CVS is equipped with a bypass, the bypass 
must include a flow monitor and sound an alarm to alert personnel that 
a bypass is being diverted to the atmosphere, or it must be equipped 
with a car-seal or lock-and-key configuration to ensure the valve 
remains in a non-diverting position. To ensure proper design, an 
assessment must be conducted and certified by a qualified professional 
engineer or in-house engineer. Covers must form a continuous 
impermeable barrier over the entire surface area of the liquid in the 
storage vessel or over the centrifugal compressor wet seal fluid 
degassing system and each cover opening shall be secured in a closed, 
sealed position (e.g., covered by a gasketed lid or cap) whenever 
material is in the unit on which the cover is installed except during 
those times when it is necessary to use an opening.
    Each CVS must be inspected using OGI or EPA Method 21 to ensure 
that the CVS operates with no identifiable emissions. Annual visual 
inspections to check for defects, such as cracks, holes, or gaps) must 
be conducted and monthly (compressor stations) or bimonthly (well sites 
and centralized production facilities) AVO inspections for leaks must 
be conducted would be a potential violation of the no identifiable 
emissions standard. Further, any leak detected would be subject to 
repair, with a first attempt at repair at five days and final repair 
within 30 days. While awaiting final repair, covers must have a gasket-
compatible grease applied to improve the seal. Delay of repair is 
allowed where the repair is infeasible without a shutdown, or it is 
determined that immediate repair would result in emissions greater than 
delaying repair. In all instances, repairs must be completed by the end 
of the next shutdown. Unsafe to inspect and difficult to inspect parts 
of the closed vent system may be designated as such but must be 
inspected according to a plan as frequently as possible, or every five 
years, respectively.
    Records of CVS and cover inspections, CVS bypass monitoring, and 
CVS design and certifications must be maintained. The CVS certification 
must be submitted in the initial annual report. Because the 
requirements for CVS and covers have been aligned for all affected 
facilities which use a CVS or cover, a new reporting section has been 
created to contain the similar requirements. Recordkeeping sections for 
CVS inspections, covers, bypass monitoring and CVS design assessment 
also have been created which are applicable to all sources which use 
CVS and covers. This will streamline

[[Page 74807]]

compliance as all affected facilities using the CVS and cover 
requirements of the rule will be subject to the same reporting and 
recordkeeping requirements.

L. Equipment Leaks at Natural Gas Processing Plants

1. NSPS OOOOb
a. November 2021 Proposal
    In the November 2021 proposal, the EPA proposed new standards of 
performance for equipment leaks at natural gas processing plants by 
revising the equipment leak standards for onshore natural gas plants to 
apply more readily to process unit equipment that has the potential to 
emit methane even though not ``in VOC service.'' The EPA also proposed 
appendix K to provide a standard method for OGI monitoring, which 
allowed the EPA to consider a wider range of LDAR programs when 
evaluating BSER for equipment leaks at onshore natural gas processing 
plants. Specifically, the EPA proposed to require bimonthly OGI 
monitoring of valves, pumps, and connectors that have the potential to 
emit methane and VOC following the protocol specified in the proposed 
appendix K. As an alternative, the EPA proposed to allow for monthly 
monitoring of pumps, quarterly monitoring of valves, and annual 
monitoring of connectors that have the potential to emit methane and 
VOC following EPA Method 21, with a leak defined as any instrument 
reading above 2,000 ppm for pumps or 500 ppm for valves and connectors. 
The EPA utilized a Monte Carlo analysis to compare these programs and 
determined that they achieved equivalent emissions reductions. See 86 
FR 63232 (November 15, 2021) for additional information. The November 
2021 proposal also included requirements for a ``first attempt at 
repair'' for all identified leaks within five days of detection, as 
well as final repair completed within 15 days of detection (except when 
delay would be allowed).
    Finally, in the November 2021 proposal, the EPA requested comments 
on certain topics. First, we requested comment 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, including whether providing an emission 
reduction target and equipment leak modeling tool to simulate LDAR 
under similar ``ideal'' program implementation conditions might 
facilitate future equivalency determinations. Second, we requested 
comment on: (1) Adding a requirement of OGI monitoring (or EPA Method 
21 monitoring for sources opting for the alternative) on open-ended 
valves or lines equipped with closure devices to ensure no emissions 
are going to the atmosphere (e.g., to ensure the cap seals the open 
end); and (2) allowing the use of OGI monitoring according to the 
proposed appendix K, to demonstrate compliance with the no detectable 
emissions requirements (in lieu of EPA Method 21) such as those for CVS 
at onshore natural gas processing plants.
b. Changes From November 2021 Proposal
    In this supplemental proposal, the EPA is proposing specific 
requirements for the individual process unit equipment type included in 
the LDAR program at onshore natural gas processing plants. This section 
describes those specific requirements for pressure relief devices, 
open-ended valves or lines, and CVS.
    Pressure Relief Devices. Consistent with the November 2021 
proposal, the EPA is proposing to require bimonthly OGI monitoring (or 
quarterly EPA Method 21 monitoring, if the alternative is used) as well 
as monitoring of each pressure relief device within 5 calendar days 
after each pressure release to detect leaks using either OGI or EPA 
Method 21. A leak is detected if any emissions are observed using OGI, 
or if an instrument reading of 500 ppm or greater is provided using EPA 
Method 21. The EPA is proposing this requirement instead of requiring a 
NDE demonstration (which is also required in NSPS OOOOa) because after 
reviewing the record to NSPS KKK (the original LDAR requirements for 
onshore natural gas processing plants), it was clear that the basis for 
the standards for pressure relief devices was a routine LDAR 
program.\241\ Because we have determined that OGI is BSER for equipment 
leaks at onshore natural gas processing plants, it is appropriate to 
require bimonthly OGI monitoring for this process unit equipment. In 
addition to this bimonthly OGI monitoring requirement, the EPA is also 
proposing to require OGI monitoring of each pressure relief device 
after each pressure release, as it is important to ensure the pressure 
relief device has reseated and is not allowing emissions to vent to the 
atmosphere. The EPA is soliciting comment on this change from a no 
detectable emissions standard to a bimonthly monitoring requirement. 
Where the EPA Method 21 option is used, we are proposing quarterly 
monitoring of the pressure relief device in addition of monitoring 
after each pressure relief. A leak is defined as an instrument reading 
of 500 ppm or greater when using EPA Method 21.
---------------------------------------------------------------------------

    \241\ See 49 FR 2645 (January 24, 1984) and EPA-450/3-82-024b.
---------------------------------------------------------------------------

    Open-Ended Valves or Lines. For open-ended valves or lines, the EPA 
is proposing to require closure devices to seal the open end, 
consistent with the requirements in NSPS OOOOa. Consistent with the 
November 2021 proposal, the proposed regulatory text would require this 
equipment standard (i.e., cap, blind flange, plug, or a second valve) 
for open-ended valves and lines. The EPA solicited comment on whether 
to require bimonthly OGI monitoring for open-ended valves and lines in 
the November 2021 proposal. We are not proposing to require routine 
periodic monitoring for open-ended valves or lines. The primary control 
requirement for open-ended valves or lines is a closure device (i.e., 
caps, blind flanges, plugs, or a second valve) and this standard is 
designed to achieve nearly 100 percent emission reductions. While it is 
possible that leaks past the closure device could occur, the EPA does 
not believe it would be cost-effective to require a full LDAR program 
for each open-ended valve or line, and has previously found this type 
of requirement not cost-effective for this type of facility.\242\ 
However, the EPA recognizes that there are opportunities to identify 
when there is a leak past the closure device as part of daily operating 
duties or required OGI surveys for other process unit equipment. 
Therefore, the EPA is proposing a requirement to complete repairs on an 
open-ended valve or line so that the closure device seals the open end 
of the valve or line when emissions are identified through any means. 
The EPA notes that repairs for this type of leak are generally 
straightforward (e.g., install new plug or cap) and cost-effective to 
complete. Further, the repair is necessary to comply with the general 
duty provisions of 40 CFR 60.5370b(b).
---------------------------------------------------------------------------

    \242\ See Document ID Nos. EPA-HQ-OAR-2010-0505-0045 and EPA-HQ-
OAR-2010-0505-7631.
---------------------------------------------------------------------------

    Closed Vent Systems. In NSPS OOOO and NSPS OOOOa, the EPA relied on 
separate CVS requirements for ones located at an onshore natural gas 
processing facility than those requirements for CVS used for other 
purposes in NSPS OOOO and NSPS OOOOa. In this proposal, the EPA is 
standardizing the requirements for CVS, as described in section IV.K of 
this preamble, with one difference.
    For CVS associated with process unit equipment affected facilities 
that are

[[Page 74808]]

used to route emissions from leaking equipment to a control device, the 
EPA is proposing a requirement to monitor the CVS at the same frequency 
(i.e., bimonthly OGI in accordance with appendix K or quarterly EPA 
Method 21) as other equipment in the process unit and to repair any 
leaks identified during the routine monitoring. Additionally, when 
leaks are identified as part of daily operating duties by any means of 
detection, we are proposing to require repairs in order to be 
consistent with the good air pollution control practices for minimizing 
emissions specified in 40 CFR 60.5370b(b). We believe it is most 
efficient and cost effective to monitor the CVS at the same frequency 
and according to the same methodology as other equipment in the process 
unit equipment affected facility (i.e., bimonthly OGI in accordance 
with appendix K or quarterly with EPA Method 21) and it is reasonable 
and prudent to require any leaks identified to be repaired.
    These proposed standards differ from our November 2021 proposal, 
which maintained EPA Method 21 inspections for CVS associated with 
process unit equipment, consistent with what is required in NSPS OOOO 
and NSPS OOOOa. Both NSPS OOOO and NSPS OOOOa require initial 
monitoring of a CVS used to comply with the equipment leak standards 
using EPA Method 21 followed by annual monitoring using visual 
inspections for defects (if constructed of hard piping) or annually 
using EPA visual inspections for defects and EPA Method 21 inspections 
(if constructed of ductwork). In this supplemental proposal, the EPA is 
proposing to allow initial monitoring using OGI in accordance with 
appendix K (or EPA Method 21 as an alternative) and annual visual 
methods for CVS where each joint, seam, or other connection is 
permanently or semi-permanently sealed (hard piping). This approach for 
initial instrument monitoring and annual visual monitoring for defects 
is consistent with the hard-piping requirements in NSPS OOOO and NSPS 
OOOOa and is also consistent with the requirements for other affected 
facilities which use a hard-piped CVS to route to a control device.
    Potential To Emit Methane or VOC. Consistent with the November 2021 
proposal, the EPA is proposing to apply the LDAR standards to process 
unit equipment that has the potential to emit methane or VOC.\243\ 
Further, the EPA is proposing that each piece of equipment is presumed 
to have the potential to emit methane or VOC unless an owner or 
operator demonstrates that the piece of equipment does not have the 
potential to emit methane or VOC. For a piece of equipment to be 
considered not to have the potential to emit methane or VOC, the owner 
or operator would need to demonstrate that the process fluids in 
contact with the process unit equipment do not contain either methane 
or VOC. Commenters \244\ suggested that the EPA maintain the 10 percent 
by weight VOC concentration threshold and add a one percent by weight 
methane concentration threshold so as to exclude ethane product 
streams, produced water streams, and wastewater streams. However, no 
additional data or analyses were provided to demonstrate that a 
threshold of one percent by weight methane would be appropriate. 
Further, recent studies indicate that produced water and wastewater 
streams can be significant sources of VOC and/or methane 
emissions.\245\ Therefore, the EPA maintains that a definition based on 
the potential to emit VOC or methane is appropriate to determine which 
process unit equipment must be monitored and repaired.
---------------------------------------------------------------------------

    \243\ See 86 FR 63182 (November 15, 2021).
    \244\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.
    \245\ ``Measurement of Produced Water Air Emissions from Crude 
Oil and Natural Gas Operations.'' Final Report. California Air 
Resources Board. May 2020. Available at: Measurement of Produced 
Water Air Emissions from Crude Oil and Natural Gas Operations 
(ca.gov).
    And ``Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-
2019: Updates for Produced Water Emissions.'' April 2021. Available 
at: https://www.epa.gov/sites/default/files/2021-04/documents/2021_ghgi_update_-_water.pdf.
---------------------------------------------------------------------------

    Repair Requirements. In this supplemental proposal, the EPA is 
proposing a definition of ``first attempt at repair'' consistent with 
the November 2021 proposal, which means an action taken for the purpose 
of stopping or reducing fugitive emissions 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. Further, we are proposing a 
definition of ``repaired,'' specific to process unit equipment affected 
facilities, meaning that equipment is adjusted, or otherwise altered, 
in order to eliminate a leak, and is re-monitored to verify that 
emissions from the equipment are below the applicable leak definition. 
Pumps subject to weekly visual inspections which are designated as 
leaking and repaired are not subject to remonitoring. We are adding 
these definitions to clarify the requirements for leak repair 
associated with process unit equipment. The EPA is not proposing to 
require replacement of leaking equipment with low-emissions (``low-e'') 
valves or valve packing or require drill-and-tap with a low-e 
injectable because it is not appropriate for all valve repairs. 
However, because this low-e equipment, which meets the specifications 
of API 622 or 624, generally will include a manufacturer written 
warranty that it will not emit fugitive emissions at a concentration 
greater than 100 ppm within the first 5 years, we believe that they can 
be a viable option for repair in some instances, as demonstrated by the 
remonitoring requirements in the rule.
    As described in the November 2021 proposal, the EPA is proposing to 
allow for delay of repair for leaks identified with OGI (or EPA Method 
21), where it is technically infeasible to complete repairs within 15 
days without a process unit shutdown. Generally, a process unit 
shutdown will generate more emissions than allowing the leak to 
continue; therefore, we are proposing to retain this delay of repair 
provision.
    Alternative Use of EPA Method 21. As discussed in the November 2021 
proposal, the EPA is proposing to allow the use of EPA Method 21 as an 
alternative to the required OGI monitoring. However, unlike NSPS OOOO 
and NSPS OOOOa, the EPA is not cross-referencing the requirements in 
NSPS VVa and is instead proposing regulatory text which incorporates 
the requirements directly into 40 CFR 60.5401b, with conforming changes 
consistent with the OGI standards, as described above for pressure 
relief devices, CVS, and repairs.
c. Summary of Proposed Requirements.
    The proposed standards will apply to the ``process unit equipment'' 
affected facility and will require that each piece of equipment that 
has the potential to emit methane or VOC conduct bimonthly (i.e., once 
every other month) OGI monitoring in accordance with appendix K to 
detect equipment leaks from pumps, valves, connectors, pressure relief 
devices, and CVS. As an alternative to the bimonthly OGI monitoring, 
EPA Method 21 may be used to detect leaks from the same equipment as 
frequencies specific to the process unit equipment type (e.g., monthly 
for pumps, quarterly for valves).
    Furthermore, this proposed rule requires that any leaks identified 
by AVO, or other detection methods from any equipment in any service, 
including open-ended valves or lines, must be repaired. The proposed 
rule includes

[[Page 74809]]

requirements for a first attempt at repair for all leaks identified 
within five days of detection, and final repair completed within 15 
days of detection (unless the delay or repair provisions are 
applicable). Delay of repair would be allowed where it is technically 
infeasible to complete repairs within 15 days without a process unit 
shutdown.
    In addition to the monitoring and repair requirements summarized 
above, this proposal includes requirements for specific types of 
equipment. First, the EPA is proposing that each open-ended valve or 
line must be equipped with a closure device (i.e., cap, blind flange, 
plug, or a second valve) that seals the open end at all times except 
during operations which require process fluid flow through the open-
ended valve or line. Next, CVS used to comply with the standards for 
process unit equipment must be monitored bimonthly using OGI (or 
quarterly using EPA Method 21 if the alternative is used). We are also 
proposing that control devices used to comply with the equipment leak 
provisions must comply with the requirements described in section IV.G 
of this preamble.
    The EPA is proposing that pressure relief devices must be monitored 
bimonthly using OGI (or quarterly using EPA Method 21 if the 
alternative is used) and five days after a pressure release to ensure 
the device has reseated after a pressure release. The proposed rule 
allows exceptions to the five-day post-pressure release monitoring 
requirement for pressure relief devices that are located in a 
nonfractionating plant (instead, the pressure relief device may 
monitored after a pressure release the next time monitoring personnel 
are onsite, but in no event may it be allowed to operate for more than 
30 calendar days after a pressure release without monitoring) or that 
are routed to a process, fuel gas system or control device.
    This proposed rule requires AVO, or other detection methodologies 
for pumps, valves, and connectors in heavy liquid service and pressure 
relief devices in light liquid or heavy liquid service and requires 
repair where a leak is found using any of those methods.
    Reporting would be required semiannually, which differs from the 
reporting for other affected facilities in NSPS OOOOb. In the initial 
semiannual report, the proposed rule will require the owner or operator 
to identify: each process unit associated with the process unit 
equipment affected facility; the number of each type of equipment 
subject to the monitoring requirements; for each month of the reporting 
period, the number of leaking equipment for which leaks were 
identified, the number of leaking equipment for which leaks were not 
repaired and the facts that explain each delay of repair; and dates of 
process unit shutdowns.
    In subsequent semiannual reports, owners and operators would be 
required to report the name of each process unit associated with the 
process unit equipment affected facility; any changes to the process 
unit identification or the number or type of equipment subject to the 
monitoring requirements; for each month of the reporting period, the 
number of leaking equipment for which leaks were identified, the number 
of leaking equipment for which leaks were not repaired and the facts 
that explain each delay of repair; and dates of process unit shutdowns.
    Required records in the proposed rule include inspection records 
consisting of equipment identification, date and start and end times of 
the monitoring inspection, inspector name, leak determination method, 
monitoring instrument identification, type of equipment monitored, 
process unit identification, appendix K records (if applicable), EPA 
Method 21 instrument readings and calibration results (if applicable) 
and, for visual inspections, the date, name of inspector and result of 
inspection. For each leak detected, the proposed rule requires 
reporting of the instrument and operator identification (or record of 
AVO method, where applicable), the date the leak was detected, the date 
and repair method applied for first attempts at repair, indication of 
whether the leak is still detected, and the date of successful repair, 
which includes results of a resurvey to verify repair. For each delay 
of repair, the proposed rule requires that the equipment is identified 
as ``repair delayed'' along with the reason for the delay, the 
signature of the certifying official, and the dates of process unit 
shutdowns which occurred while the equipment is unrepaired. 
Additionally, the proposed rule requires records of equipment 
designated for no detectable emissions; the identification of valves, 
pumps, and connectors that are designated as unsafe-to-monitor, an 
explanation stating why it is unsafe-to-monitor, and the plan for 
monitoring that equipment; a list of identification numbers for valves 
that are designated as difficult-to-monitor, an explanation stating why 
it is difficult-to-monitor, and the schedule for monitoring each valve; 
a list of identification numbers for equipment that is in vacuum 
service and a list of identification numbers for equipment designated 
as having the potential to emit methane or VOC less than 300 hr/yr. 
Finally, for CVS and control devices used to control emissions from 
process unit equipment affected facilities, the reports and records 
that demonstrate proper design and operation of the control device also 
must be maintained (see sections IV.G and IV.J. of this preamble).
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 process unit equipment that has the potential to emit methane is 
approximately $850/ton methane reduced. As explained in section III.E 
of this preamble, the cost effectiveness of this OGI monitoring option 
is within the range of costs we believe to be reasonable for methane 
reductions in this rule. Therefore, we consider a bimonthly OGI LDAR 
program following appendix K that includes all process unit equipment 
that have the potential to emit methane to be BSER for existing 
sources. The presumptive standards that are proposed in this action are 
the same as those described above for NSPS OOOOb.

M. Sweetening Units

    The EPA proposed to retain the standards found in NSPS OOOO and 
NSPS OOOOa for reducing SO2 emissions from sweetening units 
in the November 15, 2021, proposal. The EPA is proposing regulatory 
text at 40 CFR 60.5405b through 60.5408b reflect the standards of 
performance as proposed in the November 15, 2021, proposal. To clarify 
and align compliance requirements (including recordkeeping and 
reporting) for sweetening units with those of other affected 
facilities, the EPA is proposing specific language at 40 CFR 60.5405b 
which ``points'' the owner or operator to the appropriate compliance 
requirement sections (i.e., those containing initial compliance, 
continuous compliance, recordkeeping and reporting) and is proposing to 
enumerate the initial compliance requirements (of the unchanged 
standards) in section 40 CFR 60.5410b(i) and the continuous compliance 
requirements (of the unchanged standards) at 40 CFR 60.5415b(k).

N. Recordkeeping and Reporting

    In the November 2021 proposal, the EPA proposed to require 
electronic reporting of performance test reports, annual reports, and 
semiannual reports through the Compliance and Emissions

[[Page 74810]]

Data Reporting Interface (CEDRI). CEDRI can be accessed through the 
EPA's Central Data Exchange (CDX) (https://cdx.epa.gov/). As noted in 
that proposal, a description of the electronic data submission process 
is provided in the memorandum Electronic Reporting Requirements for New 
Source Performance Standards (NSPS) and National Emission Standards for 
Hazardous Air Pollutants (NESHAP) Rules, available in the docket for 
this action. The EPA also proposed to allow owners and operators the 
ability to seek extensions for electronic reporting 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 this action, the EPA is not proposing any changes from what was 
proposed in the November 2021 proposal. As noted in the November 2021 
proposal, owners and operators would be required to use the appropriate 
spreadsheet template to submit information to CEDRI for annual and 
semiannual reports. A draft version of the proposed templates for these 
reports is included in the docket for this action.\246\ The EPA 
specifically requests comment on the content, layout, and overall 
design of the templates.
---------------------------------------------------------------------------

    \246\ See Part_60_Subpart_OOOOb_60.5420b(b)_Annual_Report.xlsm 
and Part_60_Subpart_OOOOb_60.5422b(b)_Semiannual_Report.xlsx, 
available in the docket for this action.
---------------------------------------------------------------------------

V. Supplemental Proposal for State, Tribal, and Federal Plan 
Development for Existing Sources

A. Overview

    In the November 2021 proposal, the EPA proposed 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.\247\ That proposal provided 
a general overview of the state planning process triggered by the EPA's 
finalization of EG under CAA section 111(d), the EG process and 
proposed state plan requirements in more detail, and solicited comment 
on various issues related to the EG. In this supplemental proposal, the 
EPA is proposing some adjustments from the November 2021 proposal, and 
additional requirements to provide states with information needed for 
purposes of state plan development. In the following sections, in the 
same six-part ordering as the November 2021 proposal, we summarize and 
rationalize the updated and new proposed requirements. The EPA is not 
soliciting additional comment on aspects of the November 2021 proposed 
EG that are not substantively addressed or changed in this supplemental 
proposal.
---------------------------------------------------------------------------

    \247\ See 86 FR 63110 (November 15, 2021).
---------------------------------------------------------------------------

    First, we discuss changes to the proposed requirements for 
establishing standards of performance in state plans in response to a 
finalized EG. Second, we discuss changes to the proposed components of 
an approvable state plan submission. Third, we discuss the proposed 
timing for state plan submissions, and changes to the proposed timeline 
for designated facilities to come into final compliance with the state 
plan. While this section describes the requirements of the implementing 
regulations under 40 CFR part 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. Establishing Standards of Performance in State Plans

    After the EPA establishes the BSER in the final EG, as described in 
preamble section XII of the November 2021 proposal and preamble section 
IV of this supplemental proposal, each state that includes a designated 
facility must develop, adopt, and submit to the EPA its state plan 
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. The November 2021 
proposal included proposed requirements regarding two key aspects of 
implementation: establishing standards of performance for designated 
facilities, and providing measures that implement and enforce such 
standards. The November 2021 proposal additionally discussed and 
solicited comments on accommodating state programs, remaining useful 
life and other factors (RULOF), emissions inventories, and meaningful 
engagement. In the subsections below, the EPA proposes updates to 
certain presumptive standards included in the November 2021 proposal, 
and further proposes requirements related to leveraging state programs, 
RULOF, certain implementation and enforcement measures, emissions 
inventories, and meaningful engagement with pertinent stakeholders. The 
EPA believes these proposed requirements, in addition to those 
described in the November 2021 proposal, will be necessary for states 
to prepare their CAA section 111(d) state plans. The EPA is not 
reopening for comment any aspect described in the November 2021 
proposal that the EPA is not proposing to substantively address or 
update in this supplemental proposal.
    The November 2021 proposal included proposed requirements regarding 
two key aspects of implementation: establishing standards of 
performance for designated facilities and providing measures that 
implement and enforce such standards. The November 2021 proposal 
additionally discussed and solicited comments on accommodating state 
programs, RULOF, emissions inventories, and meaningful engagement. In 
the following subsections, the EPA proposes updates to certain 
presumptive standards included in the November 2021 proposal, and 
further proposes requirements related to leveraging state programs, 
RULOF, certain implementation and enforcement measures, emissions 
inventories, and meaningful engagement with pertinent stakeholders. The 
EPA believes these proposed requirements, in addition to those 
described in the November 2021 proposal, will be necessary for states 
to prepare their CAA section 111(d) state plans. The EPA is not 
reopening for comment any aspect described in the November 2021 
proposal that the EPA is not proposing to substantively address or 
update in this supplemental proposal.

1. Establish Standards of Performance for Designated Facilities

    In the November 2021 proposal, the EPA proposed the degree of 
emission limitation achievable through application of the BSER in the 
form of presumptive standards for designated facilities.\248\ The EPA 
described that there is a fundamental requirement under CAA section 
111(d) that a state plan's standards of performance reflect the 
presumptive standard, which derives from the definition of ``standard 
of performance'' in CAA section 111(a)(1). The EPA is updating Tables 
35 and 36 to reflect the updated presumptive standards in this 
supplemental proposal.
---------------------------------------------------------------------------

    \248\ 86 FR 63249 (November 15, 2021).
    \249\ As described in section IV.C of this preamble, the EPA is 
proposing a super-emitter response program under the statutory 
rationale that super-emitters are a designated facility. The EPA is 
also proposing the program under a second rationale that the super-
emitter response program constitutes work practice standards for 
certain sources and compliance assurance measures for other sources. 
Under either rationale, state plans are required to adopt the super-
emitter response program either as presumptive standards or as 
measures that provide for the implementation and enforcement of such 
standards.

[[Page 74811]]

  Table 35--Summary of Proposed EG Subpart OOOOc Presumptive Numerical
                                Standards
------------------------------------------------------------------------
                                         Proposed presumptive numerical
         Designated facility            standards in the draft emissions
                                              guidelines for GHGs
------------------------------------------------------------------------
Storage Vessels: Tank Battery with     95 percent reduction of methane.
 PTE of 20 tpy or More of Methane.
Pneumatic Controllers: Natural gas-    Methane emission rate of zero.
 driven that Vent to the Atmosphere.
Pneumatic Pumps......................  Methane emission rate of zero.
Wet Seal Centrifugal Compressors       Volumetric flow rate of 3 scfm.
 (except for those located at well
 sites).
Dry Seal Centrifugal Compressors       Volumetric flow rate of 3 scfm.
 (except for those located at well
 sites).
Reciprocating Compressors (except for  Volumetric flow rate of 2 scfm.
 those located at well sites).
------------------------------------------------------------------------

Table 36--Summary of Proposed EG Subpart OOOOc Presumptive Non-Numerical
                                Standards
------------------------------------------------------------------------
                                           Proposed presumptive non-
         Designated facility            numerical standards in the draft
                                         emissions guidelines for GHGs
------------------------------------------------------------------------
Super-Emitters.......................  Root cause analysis and
                                        corrective action following
                                        notification by an EPA-approved
                                        entity or regulatory authority
                                        of a super-emitter emissions
                                        event.\249\
Fugitive Emissions: Single Wellhead    Quarterly AVO inspections. Repair
 Only Well Sites and Small Well Sites.  for indications of potential
                                        leaks within 15 days of
                                        inspection.
                                       Fugitive monitoring continues for
                                        all well sites until the site
                                        has been closed, including
                                        plugging the wells at the site
                                        and submitting a well closure
                                        report.
Fugitive Emissions: Multi-wellhead     Quarterly AVO inspections. Repair
 Only Well Sites (2 or more             for indications of potential
 wellheads).                            leaks within 15 days of
                                        inspection.
                                       Semiannual OGI monitoring
                                        (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 monitoring continues for
                                        all well sites until the site
                                        has been closed, including
                                        plugging the wells at the site
                                        and submitting a well closure
                                        report.
Fugitive Emissions: Well Sites and     Well sites with specified major
 Centralized Production Facilities.     production and processing
                                        equipment: Quarterly OGI
                                        monitoring. (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 monitoring continues for
                                        all well sites until the site
                                        has been closed, including
                                        plugging the wells at the site
                                        and submitting a well closure
                                        report.
Fugitive Emissions: Compressor         Monthly AVO monitoring.
 Stations.                             AND
                                       Quarterly OGI monitoring.
                                        (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 and     Annual OGI monitoring. (Optional
 Compressor Stations on Alaska North    annual EPA Method 21 monitoring
 Slope.                                 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 and     (Optional) Alternative periodic
 Compressor Stations.                   screening with advanced
                                        measurement technology instead
                                        of OGI monitoring.
Fugitive Emissions: Well Sites and     (Optional) Alternative continuous
 Compressor Stations.                   monitoring system instead of OGI
                                        monitoring.
Pneumatic Controllers: Alaska (at      Natural gas bleed rate no greater
 sites where onsite power is not        than 6 scfh.
 available--continuous bleed natural
 gas-driven).
Pneumatic Controllers: Alaska (at      OGI monitoring and repair of
 sites where onsite power is not        emissions from controller
 available--intermittent natural gas-   malfunctions.
 driven).
Gas 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 of emissions
                                        to the maximum extent possible.
Equipment Leaks at Natural Gas         LDAR with OGI following
 Processing Plants.                     procedures in appendix K.

[[Page 74812]]

 
Oil Wells with Associated Gas........  Route associated gas to a sales
                                        line. If access to a sales line
                                        is not available, the gas can be
                                        used as an onsite fuel source or
                                        used for another useful purpose
                                        that a purchased fuel or raw
                                        material would serve. If
                                        demonstrated that a sales line
                                        and beneficial uses are not
                                        technically feasible, the gas
                                        can be routed to a flare or
                                        other control device that
                                        achieves at least 95 percent
                                        reduction in methane emissions.
------------------------------------------------------------------------

2. Leveraging State Programs
a. Overview
    In the November 2021 proposal, the EPA acknowledged that many 
states have programs they may want to leverage for purposes of 
satisfying their CAA section 111(d) state plan obligations (86 FR 
63252; November 21, 2021). The EPA proposed that a state plan which 
relies on a state program must establish standards of performance that 
are in the same form as the presumptive standards. The EPA further 
solicited comment on whether states relying on state 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, and how such equivalency 
demonstrations can be made in a rigorous and consistent way.
    The EPA also proposed 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 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 state programs 
are at least as stringent as the requirements of the final EG. The EPA 
noted 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 a 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 solicited 
comment on various ways in which state programs can be adopted into 
state plans particularly in situations where 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).
    The EPA believes that for states to successfully leverage their 
state programs to satisfy their CAA section 111(d) state plan 
obligations, specific criteria need to be identified for states and the 
EPA to follow in determining that a state plan meets the level of 
stringency required under the final EG, and how such equivalency 
demonstrations can be made in a rigorous and consistent way. The EPA is 
proposing such criteria for a source-by-source equivalency 
determination in this supplemental proposal.
    Some commenters requested that the EPA make an equivalency 
determination on a programmatic, rather than source-specific basis. 
Some of these commenters suggested that the EPA approve plans that are 
as stringent as EG even if they do not include identical standards or 
sources.\250\ Commenters also suggested that the EPA allow states to 
include a different form of numerical standard as long as it is 
determined to be equivalent.\251\ In addition to the suggestion 
provided, some commenters argued that the EPA is not authorized to 
approve state limitations that were not derived using CAA section 
111(d) standard setting methods.
---------------------------------------------------------------------------

    \250\ See Docket ID Nos. EPA-HQ-OAR-2021-0317-0581, EPA-HQ-OAR-
2021-0317-0775, EPA-HQ-OAR-2021-0317-0926, and EPA-HQ-OAR-2021-0317-
1267.
    \251\ See Docket ID Nos. EPA-HQ-OAR-2021-0317-0558, EPA-HQ-OAR-
2021-0317-0761, EPA-HQ-OAR-2021-0317-0769, and EPA-HQ-OAR-2021-0317-
1267.
---------------------------------------------------------------------------

    The following sections discuss EPA's proposal for how states with 
programs that regulate GHGs in the form of methane from oil and natural 
gas sources may establish source-by-source equivalency with the EPA's 
designated facility presumptive standards under EG OOOOc. Consistent 
with that discussion, the EPA is also proposing to interpret CAA 
section 111 to authorize states to establish standards of performance 
for their sources that, in the aggregate, would be equivalent to the 
presumptive standards. The 2019 Affordable Clean Energy (ACE) Rule 
interpreted CAA section 111 to require that each state establish for 
each source a standard of performance that reduces that source's 
emissions, and to preclude the type of compliance flexibility that the 
EPA is now proposing. 84 FR 32556-57 (July 8, 2019). In 2021, the D.C. 
Circuit vacated the ACE Rule, holding, among other things, that CAA 
section 111(d) does not preclude states from allowing certain 
compliance flexibilities, including trading or averaging of emission 
limits. American Lung Ass'n v. EPA, 985 F.3d 914, 957-58 (D.C. Cir. 
2021). In 2022, the U.S. Supreme Court reversed the D.C. Circuit's 
judgment regarding the ACE Rule's embedded repeal of the Clean Power 
Plan on other grounds. West Virginia v. EPA, 142 S. Ct. 2587 (2022). 
The Supreme Court made clear that CAA section 111 authorizes the EPA to 
determine the BSER and the amount of emission limitation that state 
plans must achieve, id. at 2601-02, but the Supreme Court did not 
address the D.C. Circuit's interpretation of CAA section 111 as to the 
state's compliance flexibilities. Id. at 2615-16.
    The EPA has reconsidered the ACE Rule's interpretation of CAA 
section 111, and now disagrees with it. Section 111(d) does not, by its 
terms, preclude states from having flexibility in determining which 
measures will best achieve compliance with the EPA's emission 
guidelines. Such flexibility is consistent with the framework of 
cooperative federalism that CAA section 111(d) establishes, which vests 
states with substantial discretion. CAA section 111(d) thus permits 
each state, when appropriate, to adopt measures that allow its sources 
to meet their emission limits in the aggregate. In addition, the EPA 
agrees with the separate set of reasons that the D.C. Circuit gave in 
holding that CAA section 111(d) does not preclude a state from allowing 
its sources compliance flexibilities. American Lung Ass'n v. EPA, 985 
F.3d 914, 957-58. Thus, it is the EPA's

[[Page 74813]]

position that CAA section 111(d) authorizes the EPA to allow states, in 
particular rules, to achieve the requisite emission limitation through 
the aggregate reductions from their sources, and the EPA is accordingly 
proposing to authorize states to leverage their state programs to 
satisfy their CAA section 111(d) state plan obligations pursuant to EG 
OOOOc, subject to requirements discussed in the following sections.
    The EPA intends shortly to propose revisions to the implementing 
regulations for CAA section 111(d) at 40 CFR part 60, subpart Ba. The 
EPA intends, in that rulemaking, to further clarify that CAA section 
111(d) and the implementing regulations authorize the EPA to, in 
particular rules, allow states flexibility and discretion in 
establishing standards of performance that meet the emission 
guidelines, including standards that permit their sources to comply via 
methods such as trading or averaging. The EPA encourages interested 
persons to submit comments on this issue in that rulemaking for the 
implementing regulations, and the EPA intends to finalize that 
rulemaking before finalizing this oil and gas rulemaking.
b. Types of Equivalency Evaluations
    For purposes of this supplemental proposal, the EPA contemplated 
two types of equivalency evaluations that could be considered when 
comparing state programs against the stringency of EG OOOOc. These 
include: (1) Total program evaluation, and (2) source-by-source 
evaluation.
i. Total Program Evaluation
    The first type of equivalency evaluation the EPA assessed is a 
total program evaluation, meaning assessing reductions and controls 
across all or different designated facilities. A total program 
evaluation could entail that some sources would get more reductions 
than the presumptive standards in the EG and others less reductions, 
but overall reductions are equal or greater than what would be achieved 
in the aggregate across all designated facilities by implementing the 
presumptive standards. A total program evaluation may look different 
for states that have designated facilities in the production, 
processing, and transmission and storage segments compared to states 
that only have designated facilities in the transmission and storage 
segment. The EPA recognizes that potentially allowing for total program 
equivalency could, in theory, reduce burden on states by allowing 
states with programs to rely more on those programs for their state 
plan submittal without needing to revise standards for specific 
designated facilities in order to match the presumptive standards. 
Furthermore, the EPA recognizes that burden may be reduced for owners 
and operators of designated facilities because they would not have to 
comply with two different sets of regulations. However, the EPA has 
identified the following challenges and complexities that are unique to 
the Crude Oil and Natural Gas source category and is therefore 
proposing to disallow state plans from using total program equivalence 
to meet the requirements of a final OOOOc EG.
    One such consideration is that state programs may include sources 
that are not designated facilities. For example, New Mexico, 
Pennsylvania, and Ohio have state standards for pigging activities. The 
EPA is not proposing to determine a BSER or presumptive standards for 
pigging activities in this supplemental proposal. Because CAA section 
111(d)(1) only provides that state plans may include standards of 
performance and certain other requirements for designated facilities, 
the EPA interprets the statute as not allowing the EPA to approve, and 
thereby render federally enforceable, state plan requirements that 
extend to sources that are not designated facilities. Therefore, it is 
not appropriate to allow a state to account for non-designated 
facilities as part of their state plan submission for any purpose, 
including for demonstrating program equivalency, even if a state 
regulates such sources as a matter of state law.\252\
---------------------------------------------------------------------------

    \252\ The EPA acknowledges that states may choose to regulate 
non-designated facilities under state law for other purposes than to 
satisfy their CAA section 111(d) state plan submission.
---------------------------------------------------------------------------

    In addition, the EPA also interprets CAA section 111(d) as not 
allowing the EPA to approve state plan requirements for different 
pollutants than those designated pollutants that are regulated in the 
EG. The EPA is aware that while numerous states have programs in place 
that regulate emissions from the designated facilities that the EPA is 
proposing presumptive standards for, many of those programs do not 
regulate GHGs in the form of limitations on methane.
    The EPA also proposed in the November 2021 proposal that states are 
generally expected to establish the same non-numerical standards and if 
a state chooses to utilize a different design, equipment, work 
practice, and/or operational standard then the state must include in 
its plan a demonstration of equivalency that is consistent with 
alternative means of emissions limitations (AMEL) provisions. Some 
state commenters agreed with the EPA that states are expected to 
establish the same non-numerical standards.\253\ The EPA recognizes if 
a state sought to utilize a different design, equipment, work practice, 
and/or operational standard, a demonstration of equivalency that is 
consistent with AMEL provisions would likely be technically difficult 
because many of the presumptive standards in the EG OOOOc are work 
practice standards that do not quantify emissions. This would suggest 
that the equivalency evaluation would need to be a qualitative analysis 
rather than a quantitative analysis because not all states have 
comprehensive source and source-specific emissions inventory data to 
base a stringency comparison on emissions reductions alone. The EPA 
believes this qualitative comparison would be extremely complicated on 
a holistic total program basis given that there are nine types of 
designated facilities with proposed presumptive standards, of which, 
five have numerical limits and two are in the format of work practice 
standards. Without a clear structure for this evaluation to address the 
complexities of the Crude Oil and Natural Gas source category, the EPA 
is concerned that emission reductions and controls consistent with the 
EG, and consistency of implementation across state plans, would be 
compromised. Similarly, the EPA proposed that for designated facilities 
with numerical presumptive standards, states are expected to establish 
the same form of numerical standards, but the EPA also took comment on 
whether to allow states to include a different form of numerical 
standards for these facilities so long as states demonstrate 
equivalency. Some state commenters suggested that the ability to 
include a different form of numerical standard in state plans is 
consistent with the cooperative federalism structure of CAA section 
111(d).\254\ While states asked for this flexibility, state commenters 
did not clearly provide specific examples of where a state already has 
a different form of a numerical standard that would necessitate this 
flexibility. The EPA is also concerned that there may be insufficient 
state comprehensive source and source-specific emissions inventory data 
to make the requisite technical evaluation.
---------------------------------------------------------------------------

    \253\ See Docket ID No. EPA-HQ-OAR-2021-0317-1267.
    \254\ See Docket ID No. EPA-HQ-OAR-2021-0317-1267.

---------------------------------------------------------------------------

[[Page 74814]]

    Another complicating scenario informing the EPA's proposal to 
disallow total program equivalence is that there are instances where a 
state covers part or subset of the EG designated facility's 
applicability definitions. For example, Colorado requires the use of 
non-emitting \255\ pneumatic controllers with specific exceptions. One 
exception is that operators do not have to retrofit their controllers 
to become non-emitting if on a company-wide basis, the average 
production from producing wells in 2019 is less than 15 barrel of oil 
equivalent/day/well. However, the EPA's supplemental proposal for 
pneumatic controllers, as discussed in section VII.D of this preamble, 
proposes a methane emission rate of zero with no applicability site 
wide production or other threshold thus covering a broader group of 
pneumatic controllers. If the EPA were to permit total program 
equivalence where state programs do not align with the EG, then there 
could be situations where a state would be allowed to forgo regulating 
some designated facilities that the EPA has determined are reasonable 
to control.
---------------------------------------------------------------------------

    \255\ The terms ``zero emissions'' and ``non-emitting'' are used 
to describe pneumatic controllers. In Colorado, 5 CCR Regulation 7, 
Part D, Section III, defines a ``non-emitting'' controller as ``a 
device that monitors a process parameter such as liquid level, 
pressure or temperature and sends a signal to a control valve in 
order to control the process parameter and does not emit natural gas 
to the atmosphere. Examples of non-emitting controllers include but 
are not limited to: no-bleed pneumatic controllers, electric 
controllers, mechanical controllers and routed pneumatic 
controllers.'' A routed pneumatic controller is defined as ``a 
pneumatic controller that releases natural gas to a process, sales 
line or to a combustion device instead of directly to the 
atmosphere.'' The EPA is proposing that pneumatic controllers must 
be ``zero emission'' controllers. The difference in non-emitting, as 
defined by Colorado and zero emissions, as proposed in this action, 
is that pneumatic controllers for which emissions are captured and 
routed to a combustion device are not considered to be ``zero 
emission'' controllers. Therefore, routing to a combustion device is 
not an option for compliance with the proposed EG OOOOc.
---------------------------------------------------------------------------

    For these reasons and the critical need to provide clear regulatory 
certainty to the hundreds of thousands of designated facilities in this 
uniquely large source category, the EPA does not think a total program 
evaluation would guarantee that the same emissions reductions as 
required by the EG would be achieved. The EPA solicits comments on how 
a total program evaluation could be established in a way that would 
address the complexities of the Crude Oil and Natural Gas source 
category and concerns the EPA has identified.
ii. Source-by-Source Evaluation
    The second type of equivalency considered is a source-by-source 
evaluation for a specific designated facility, such as between all 
storage vessels located in a state or between a subset of centrifugal 
compressors. A source-by-source evaluation could entail a state 
conducting equivalency evaluation for one or more designated facilities 
and their respective presumptive standards. In theory, if a state were 
to do a source-by-source evaluation for each individual designated 
facility in its state, this could be considered a form of total program 
evaluation that is distinct from the type of total program evaluation 
described above that the EPA is proposing to disallow, where 
equivalence can be evaluated across different designated facilities 
rather than designated facilities of the same type. A source-by-source 
evaluation assumes that all sources in a state that meet the 
applicability definition for a specific designated facility (e.g., 
pneumatic controllers, pneumatic pumps, and reciprocating compressors), 
would in the aggregate have to achieve the same or better reductions of 
the same designated pollutant as if the state instead imposed the 
presumptive standards required under the EG. A source-by-source 
evaluation, in theory, may push states to make changes to their state 
rules, which may increase burden on states, but is likely a more 
reliable way to determine that the state is achieving all emission 
reductions equivalent to implementing the presumptive standards. Given 
that state programs do vary considerably, a source-by-source evaluation 
would allow states to pick and choose which state standards they want 
to leverage for purpose of their state plan development. It is 
theoretically less technically difficult to evaluate equivalency on a 
source-by-source basis for the Crude Oil and Natural Gas source 
category compared to total program equivalence. The EPA is proposing 
five basic criteria for when states may use a source-by-source 
evaluation as part of their state plans (discussed in section 
V.B.2.b.iii of this preamble).
    An example of a source-by-source stringency comparison is the 
comparison the EPA prepared when assessing the stringency of state 
fugitive emissions monitoring programs compared to what was required 
under NSPS OOOOa.\256\ Similar to that example, the EPA proposes that 
any stringency comparison conducted to determine equivalence with the 
proposed presumptive standards that are work practices will need to be 
designated facility specific and the qualitative assessment will need 
to be tailored to ensure that the correct technical metrics are being 
compared.
---------------------------------------------------------------------------

    \256\ Memorandum: Equivalency of State Fugitive Emissions 
Programs for Well Sites and Compressor Stations to Proposed 
Standards at 40 CFR part 60, subpart OOOOa. See Document ID No. EPA-
HQ-OAR-2017-0483-2277.
---------------------------------------------------------------------------

iii. Source-by-Source Evaluation Criteria and Methodology
    In order to implement a source-by-source evaluation, the EPA is 
proposing five basic criteria to determine whether a source-by-source 
evaluation can be considered for equivalency. The criteria are: (1) 
Designated facility, (2) designated pollutant, (3) standard type/format 
of standard (e.g., numeric, work practice), (4) emission reductions 
(with consideration of applicability thresholds and exemptions), and 
(5) compliance assurance requirements (e.g., monitoring, recordkeeping, 
and reporting).
    In the following paragraphs, the EPA proposes a source-by-source 
equivalency step-by-step approach followed by an example for 
hypothetical state rules illustrating how states could implement the 
proposed approach when conducting a state rule equivalency 
determination with the proposed presumptive standards.
    Step One. Is state rule designated facility definition, pollutant, 
and format the same? The first questions that a state needs to answer 
is whether their program defines their regulated emissions source 
similar to how the EPA defines a designated facility. Do their program 
requirements for the designated facility regulate the same pollutant, 
and is the format of the standard the same (e.g., work practice or 
performance based numerical standard)? If the answer is no to any of 
these questions (e.g., state program regulates VOC and not methane), 
then the state plan cannot include an equivalency determination with 
the EPA's proposed presumptive standards for the designated facility. 
If the answer is yes to all of these questions, a state would proceed 
to Step Two.
    Step Two. Emissions Reductions. A state plan needs to include a 
demonstration that the state requirements for designated facilities 
achieve the same or greater emissions reduction as the designated 
facility presumptive standards. A state would have several options to 
make this demonstration.

[[Page 74815]]

    The first option would be to make a demonstration that the 
designated facility state standard achieves the same emission reduction 
as the designated facility BSER analysis using the EPA model plant/
representative facility. The second option would be to make a 
demonstration that the designated facility state standard achieves the 
same or greater emissions reduction ``in real life'' as the designated 
facility model plant/representative facility emission reduction in the 
BSER analysis. The third option would be that a state could apply the 
designated facility presumptive standard to ``real life'' (e.g., using 
activity (number of sources) and actual emissions data) and calculate 
the state-wide emission reduction that would be achieved, and then 
demonstrate that the state program requirements for a designated 
facility would achieve the same or greater emissions reduction. If 
emissions reductions from the implementation of the state rule are less 
than would be achieved from the implementation of the presumptive 
standards, the state cannot make an equivalency determination with the 
EPA's proposed presumptive standards. If emissions reductions from the 
implementation of the state rule are the same or greater than would be 
achieved from the implementation of the presumptive standards, a state 
would proceed to Step Three.
    Step Three. Make demonstration that compliance measures included 
for a designated facility under a state program are at least as 
effective as those in the presumptive standard. Once a state has 
determined that the emission reductions from the implementation of the 
state requirements for a designated facility are the same or greater 
than would be achieved by the implementation of the presumptive 
standards for a designated facility under Step Two, a state plan would 
need to include a demonstration that compliance measures (e.g., 
monitoring, recordkeeping and reporting requirements) are sufficient to 
ensure continued compliance with the standards and projected emission 
reductions.
    Centrifugal Compressor Examples--Comparison of Primary Presumptive 
Standards With 4 Hypothetical Examples.
    Table 37 provides examples of the application of the steps outlined 
above for five hypothetical state rules for reciprocating compressors 
at gathering and boosting stations in the production segment. The 
parameters for the presumptive standard for reciprocating compressors 
are as follows.
    (1) The designated facility is a single reciprocating compressor.
    (2) The designated pollutant is methane, using volumetric flow rate 
as a surrogate for methane).
    (3) The standard type/format of standard is a numerical standard (2 
scfm volumetric flow rate).
    (4) The estimated methane emission reductions for the model 
compressor in the BSER analysis for the presumptive standard was 92 
percent reduction.
    (5) The compliance assurance requirements include the requirement 
to measure the flow rate once every 8,760 operating hours and maintain 
records.

  Table 37--Reciprocating Compressor Designated Facility Presumptive Standards Equivalency Evaluation Examples
----------------------------------------------------------------------------------------------------------------
                                                            Equivalency determination steps
                                     ---------------------------------------------------------------------------
  Designated facility requirements           Step one--
                                         applicability and       Step two--emission     Step three-- compliance
                                         format of standard           reduction            assurance measures
----------------------------------------------------------------------------------------------------------------
Example A:
    Designated Facility: Single       FAIL--format of
     Reciprocating Compressor at       standard not
     Gathering and Boosting.           equivalent.
    Designated Pollutant: Methane...
    Format of Standard: Work
     Practice (Change out rod
     packing every 3 years).
    Estimated Emission Reduction
     (Basis): 56% (model compressor
     basis).
    Compliance Assurance
     Requirements: Records of
     changeout.
Example B:
    Designated Facility: Single       PASS...................  PASS..................  PASS.
     Reciprocating Compressor at
     Gathering and Boosting.
    Designated Pollutant: Total
     hydrocarbon as Surrogate for
     Methane.
    Format of Standard: Numerical
     (Collect and route to control
     to achieve 95% reduction).
    Estimated Emission Reduction
     (Basis): 95% (model compressor
     basis).
    Compliance Assurance
     Requirements: Performance test
     of control device, continuous
     parameter monitoring,
     recordkeeping and reporting.
Example C:
    Designated Facility: Single       FAIL--format of
     Reciprocating Compressor at       standard not
     Gathering and Boosting.           equivalent.
    Designated Pollutant: Total Gas
     Flow rate as surrogate for
     methane.
    Format of Standard: Directed
     Inspection and Maintenance
     (Measure flow rate annually and
     replace or repair if volumetric
     flow is greater than 3 scfm).
    Estimated Emission Reduction
     (Basis): 92% (model compressor
     basis).
----------------------------------------------------------------------------------------------------------------

[[Page 74816]]

 Table 37--Reciprocating Compressor Designated Facility Presumptive Standards Equivalency Evaluation Examples--
                                                    Continued
----------------------------------------------------------------------------------------------------------------
                                                            Equivalency determination steps
                                     ---------------------------------------------------------------------------
  Designated facility requirements           Step one--
                                         applicability and       Step two--emission     Step three-- compliance
                                         format of standard           reduction            assurance measures
----------------------------------------------------------------------------------------------------------------
    Compliance Assurance
     Requirements: Records of
     measurements, records of
     corrective actions if greater
     than 3 scfm, records of new
     measurement to demonstrate less
     than 3 scfm after corrective
     action.
Example D:
    Designated Facility: Single
     Reciprocating Compressor at
     Gathering and Boosting.
    Designated Pollutant: Total gas
     flow rate as surrogate for
     methane.
    Format of Standard: Numerical: 5
     scfm.
    Estimated Emission Reduction
     (Basis): using analysis of
     state-wide emissions from
     actual reciprocating
     compressors, estimated that
     presumptive standard would
     achieve 85% reduction over the
     state, state rule would achieve
     87% reduction..
    Compliance Assurance              PASS...................  PASS Demonstrated that  PASS.
     Requirements: Measure                                      the ``real life''
     volumetric flow rate once every                            state-wide emission
     six months, record results..                               reduction for state
                                                                rule was greater than
                                                                the ``real-life''
                                                                reduction for the
                                                                presumptive standard..
Example E:
    Designated Facility: Single       PASS...................  FAIL--did not           .........................
     Reciprocating Compressor at                                demonstrate that the
     Gathering and Boosting.                                    BSER presumptive
                                                                standard model
                                                                facility reduction
                                                                was met.
    Designated Pollutant: Total gas
     flow rate as surrogate for
     methane.
    Format of Standard: Numerical: 4
     scfm.
    Estimated Emission Reduction
     (Basis): 88% (analysis of state-
     wide emissions from actual
     reciprocating compressors).
    Compliance Assurance
     Requirements: Measure
     volumetric flow rate once every
     six months, record results.
----------------------------------------------------------------------------------------------------------------

    The EPA solicits comment on the EPA's proposed state program 
equivalency demonstration methodology and evaluating criteria for when 
state plans may include standards of performance based on an 
equivalency demonstration. Specifically, the EPA solicits comments on 
other criteria than what the EPA is proposing should be considered; and 
whether there are other additional qualitative factors/criteria need to 
be included to make an effective stringency evaluation for different 
types of different design, equipment, work practice, and/or operational 
standards.
c. General Permitting Programs
    The EPA also recognizes that some states may regulate the 
designated facilities proposed to be regulated under the EGs through a 
general permit program. For example, general permits often include 
standardized terms and conditions related to emissions control, 
compliance certification, notification, recordkeeping, reporting, and 
source testing requirements. The EPA is not proposing a regulatory 
amendment on this point but confirms that the implementing regulations 
under subpart Ba allows for standards of performance and other state 
plan requirements to be established as part of state permits and 
administrative orders, which are then incorporated into the state plan. 
See 40 CFR 60.27a(g)(2)(ii).
    However, the EPA notes that the permit or administrative order 
alone may not be sufficient to meet the requirements of an EG or the 
implementing regulations, including the completeness criteria under 40 
CFR 60.27a(g). For instance, a plan submission must include supporting 
material demonstrating the state's legal authority to implement and 
enforce each component of its plan, including the standards of 
performance. Id. at 40 CFR 60.27a(g)(2)(iii). In addition, EG OOOOc may 
also require demonstrations that may not be satisfied by terms of a 
permit or administrative order. To the extent that these and other 
requirements are not met by the terms of the incorporated permits and 
administrative orders, states will need to include materials in a state 
plan submission demonstrating how the plan meets those requirements.
3. Remaining Useful Life and Other Factors (RULOF)
    Under CAA section 111(d), the EPA is required to promulgate 
regulations under which states submit plans establishing standards of 
performance for designated facilities. While states establish the 
standards of performance, there is a fundamental obligation under CAA 
section 111(d) that such standards reflect the degree of emission 
limitation achievable through the application of the BSER, as 
determined by the EPA. As previously described, this obligation derives 
from the definition of ``standard of performance'' under CAA section 
111(a)(1). The EPA identifies the degree of emission limitation 
achievable through application of the BSER as part of its EG. 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

[[Page 74817]]

applying a standard of performance to a particular designated facility, 
to take into account the designated facility's RULOF. The EPA's 
implementing regulations under 40 CFR 60.24a(e) allows a state to 
consider a designated facility's RULOF in applying a standard of 
performance less stringent than the presumptive level of stringency 
given in an EG to a particular source, provided that the state makes 
the required demonstration under this provision. However, as described 
further below, this provision does not provide clear parameters for 
states on how and when to apply a standard less stringent than the 
presumptive level of stringency given in an EG to a particular source. 
The EPA intends to propose clarifying revisions to this provision under 
the implementing regulations in an upcoming rulemaking that would apply 
generally to new EG promulgated under CAA section 111(d). While 
inviting comments on the application of these proposed revisions in the 
context of the oil and gas sector in this rulemaking, the EPA also 
encourages the public to provide comments on these proposed revisions 
more generally in that upcoming rulemaking process to amend the 
implementing regulations. The EPA intends to finalize that rulemaking 
before finalizing this oil and gas rulemaking.
    Consistent with its intended revisions to the implementing 
regulations, the EPA is proposing to supersede the current 40 CFR 
60.24a(e) by providing requirements specific to EG OOOOc for the 
consideration of RULOF in state plans to set a less stringent standard 
for a particular source. The EPA notes that the EPA considers the 
application of the proposed RULOF provisions to apply in circumstances 
distinct from source-by-source evaluation discussed earlier in section 
V.B.2. In other words, these provisions apply where a state intends to 
depart from the presumptive standards in EG OOOOc and propose a less 
stringent standard for a designated facility (or class of facilities), 
and not where a state intends to comply by demonstrating that a 
facility or group of facilities subject to a state program would, in 
the aggregate, achieve equivalent or better reductions than if the 
state instead imposed the presumptive standards required under the EG. 
The EPA's proposed RULOF requirements for the application of a less 
stringent standard and rationale are as follows.
    The RULOF provision currently under 40 CFR 60.24a(e) allows states 
to consider RULOF to apply a less stringent standard of performance for 
a designated facility or class of facilities if they demonstrate one of 
the three following circumstances: 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 
specify that, absent such a demonstration, the state's standards of 
performance must be ``no less stringent than the corresponding'' EG. 40 
CFR 60.24a(c). This supplemental proposal largely retains the substance 
of this threshold provision for purposes of EG OOOOc, including the 
three circumstances under which a less stringent standard of 
performance may be applied, and provide further clarification of what a 
state must demonstrate in order to invoke RULOF when submitting a state 
plan. Specifically, the EPA proposes to require the state to 
demonstrate that a particular facility cannot reasonably achieve the 
degree of emission limitation achievable through application of the 
BSER, based on one or more of the three circumstances. The EPA is also 
proposing to clarify the third circumstance by specifying that states 
may apply a less stringent standard if factors specific to the facility 
are fundamentally different than those considered by the EPA in 
determining the BSER. Subsection a. describes the statutory and 
regulatory background, and subsection b. explains the agency's 
rationale for its proposal. Subsections c-h describe further proposed 
additions to the RULOF provision in cases where states seek to apply a 
standard that is less stringent than the degree of emission limitation 
achievable through application of the BSER. These proposed additions 
include requirements for the calculation of a less stringent standard, 
contingency requirements in cases where an operating condition is the 
basis for RULOF, and the consideration of disproportionately impacted 
communities. Finally, subsection i. describes the proposal to address 
cases where states seek to apply a more stringent standard.
a. Statutory and Regulatory Background
    The 1970 version of CAA section 111(d) made no reference to the 
consideration of RULOF in the context of standards for existing 
sources. In the 1975 regulations promulgating subpart B, however, the 
EPA included a so-called variance provision. For health-based 
pollutants, states could apply a standard of performance less stringent 
than the EPA's EGs based on cost, physical impossibility, and other 
factors specific to a designated facility that make the application of 
a less stringent standard significantly more reasonable. 40 CFR 
60.24(f). For welfare-based pollutants, states could apply a less 
stringent standard by balancing the requirements of an EG ``against 
other factors of public concern.'' 40 CFR 60.24(d). As part of the 1977 
CAA amendments, Congress amended CAA section 111(d)(1) to require that 
the EPA's regulations under this section ``shall permit the State in 
applying a standard of performance to any particular source under a 
plan submitted under this paragraph to take into consideration, among 
other factors, the remaining useful life of the existing source to 
which such standard applies.'' At the time, the EPA considered the 
variance provision under subpart B to meet this requirement and did not 
revise the provision subsequent to the 1977 CAA amendments until 
promulgating new implementing regulations in 2019 under subpart Ba. As 
part of the 2019 revisions, the EPA removed the health and welfare-
based pollutants distinction and collapsed the associated requirements 
of the previous variance provision into a single, new RULOF provision 
under 40 CFR 60.24a(e). 84 FR 32520, 32570. The D.C. Circuit vacated 
several timing-related provisions under 40 CFR part 60, subpart Ba; 
however, Petitioners did not challenge, and the court did not vacate, 
the new RULOF provision under 40 CFR 60.24a(e). Am. Lung Assoc. v. EPA, 
985 F.3d at 991 (D.C. Cir. 2021) (ALA).\257\
---------------------------------------------------------------------------

    \257\ The Supreme Court subsequently reversed and remanded the 
D.C. Circuit's opinion. West Virginia v. EPA, 142 S.Ct. 2587 (June 
30, 2022). However, no Petitioner sought certiorari on, and the West 
Virginia decision did not implicate, the D.C. Circuit's vacatur of 
portions of subpart Ba.
---------------------------------------------------------------------------

b. Rationale for the Proposed Revisions
    As previously described, the statute expressly requires the EPA to 
permit states to consider RULOF for a particular designated facility 
when applying a standard of performance to that facility. The 
consideration of remaining useful life in particular can be an 
important consideration, as the cost of control for a specific 
designated facility that is not expected to operate in the long term, 
relative to other designated facilities in the source category, could 
significantly vary from the average cost calculations done as part of 
the BSER determination for the source category as a whole. In such an 
instance, and in others as described throughout this section, a less 
stringent standard may be more reasonable to

[[Page 74818]]

apply than a standard of performance that reflects the presumptive 
level of stringency.
    In order to understand how states may have dealt with this issue in 
their programs, the EPA examined several existing state oil and natural 
gas regulations and programs. Based on our examination, we did not 
identify any provision in any of the state oil and natural gas 
regulations that included a less stringent standard for equipment or 
operations with a shortened lifespan. The EPA is interested in 
obtaining information on whether this situation exists in state oil and 
natural gas rules that we may not have identified in our search. In 
addition, the EPA is soliciting comment on situations where state rules 
for industries other than the oil and natural gas industry include less 
stringent requirements for sources that are soon to retire. If these 
situations exist, the EPA is not only interested in the less stringent 
requirements as they compare to the ``normal'' standards, but also how 
the state evaluated the suitability of the less stringent requirements.
    As currently written, the RULOF provision in subpart Ba does not 
provide clear parameters for states on how and when to apply a standard 
less stringent than the presumptive level of stringency given in an EG 
to a particular source. As written, the references to reasonableness in 
this provision are potentially subject to widely differing 
interpretations and inconsistent application among states developing 
plans, and by the EPA in reviewing them. Without a clear analytical 
framework for applying RULOF, the current provision may be used by 
states to set less stringent standards that could effectively undermine 
the overall presumptive level of stringency envisioned by the EPA's 
BSER determination and render it meaningless.\258\ Such a result is 
contrary to the overarching purpose of CAA section 111(d), which is 
generally to require meaningful emission reductions from designated 
facilities based on the BSER.
---------------------------------------------------------------------------

    \258\ CAA section 111(d) does not require states to consider 
RULOF, but rather requires that the EPA's regulations ``permit'' 
states to do so. In other words, the EPA must provide states with 
the ability to account for RULOF, but states may instead choose to 
establish a standard of performance that is the same as the 
presumptive level of stringency set forth in the EGs. The 
optionality, rather than mandate, for states to account for RULOF 
supports the notion that this provision is not intended to undermine 
the presumptive level of stringency in an EG for the source category 
broadly. Additionally, the EPA notes that it is not aware of any CAA 
section 111(d) EGs under which an EPA-approved state plan has 
previously considered RULOF to apply a standard of performance that 
deviates from the presumptive level of stringency. Clarifying 
parameters may better enable states to effectively use this 
provision in developing their state plans.
---------------------------------------------------------------------------

    Additionally, while states have discretion to consider RULOF under 
CAA section 111(d), it is the EPA's responsibility to determine whether 
a state plan is ``satisfactory,'' \259\ which includes evaluating 
whether RULOF was appropriately considered. The relevant dictionary 
meaning of ``satisfactory'' is ``fulfilling all demands or 
requirements.'' The American College Dictionary 1078 (C.L. Barnhart, 
ed. 1970). Thus, the most reasonable interpretation of a ``satisfactory 
plan'' is a CAA section 111(d) plan that meets the applicable 
conditions or requirements, including those under the implementing 
regulations that the EPA is directed to promulgate pursuant to CAA 
section 111(d), including the provisions governing the application of 
RULOF.\260\
---------------------------------------------------------------------------

    \259\ CAA section 111(d)(2)(A) authorizes the EPA to promulgate 
a Federal plan for any state that ``fails to submit a satisfactory 
plan'' establishing standards of performance under CAA section 
111(d)(1). Accordingly, the EPA interprets ``satisfactory'' as the 
standard by which the EPA reviews state plan submissions.
    \260\ Although there is no case law specifically on the standard 
of review of a CAA section 111(d)(1) state plan or the EPA's duty to 
approve satisfactory plans, the EPA's action on a CAA section 
111(d)(1) state plan is structurally identical to the EPA's action 
on a state implementation plan (SIP). Under section 110(k)(3), EPA 
must approve a SIP that meets all requirements of the Act. See Train 
v. NRDC, 421 U.S. 60 (1975) (discussing the 1970 version of the 
Act); Virginia v. EPA, 108 F.3d 1397, 1408-10 (D.C. Cir. 1995) 
(discussing the 1970, 1977, and 1990 versions).
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    The EPA's determination of whether each plan is ``satisfactory'', 
including the application of RULOF, must be generally consistent from 
one plan to another. If the states do not have clear parameters for how 
to consider RULOF when applying a standard of performance to a 
designated facility, then they face the risk of submitting plans that 
the EPA may not be able to consistently approve as satisfactory. For 
example, under the current broadly structured provision, two states 
could consider RULOF for two identically situated designated facilities 
and apply completely different standards of performance on the basis of 
the same factors. In this example, it may be difficult for the EPA to 
substantiate finding both plans satisfactory in a consistent manner, 
and the states and sources risk uncertainty as to whether each of the 
differing standards of performance would be approvable. Accordingly, 
providing a clear analytical framework for EG OOOOc for the invocation 
of RULOF will provide regulatory certainty for states and the regulated 
community as they seek to craft satisfactory plans that the EPA can 
ultimately approve.
    For these reasons, the EPA is proposing the RULOF provision under 
subpart OOOOc, consistent with the statutory construct and goals of CAA 
section 111(d), in order to provide states and sources with clarity 
regarding the requirements that apply to the development and 
approvability of state plans that consider RULOF when applying a 
standard of performance to a particular designated facility. Below, we 
describe the guiding principles for the EPA's proposed revisions.
    CAA section 111(a)(1) requires that the EPA determine the BSER is 
``adequately demonstrated'' for the regulated source category. In 
determining whether a given system of emission reduction qualifies as 
BSER, CAA section 111(a)(1) requires that the EPA take into account 
``the cost of achieving such reduction and any non-air quality health 
and environmental impact and energy requirements.'' The EPA's proposed 
RULOF provision does so by tethering the states' RULOF demonstration to 
the statutory factors the EPA considered in the BSER determination. 
This is appropriate under the statute because the EPA will have 
demonstrated that the BSER identified in EG OOOOc is ``adequately 
demonstrated'' as achievable for sources broadly within the Crude Oil 
and Natural Gas source category. Therefore, RULOF is appropriately 
applied to permit states to address instances where the application of 
the BSER factors to a particular designated facility is fundamentally 
different than the determinations made to support the BSER and 
presumptive level of stringency in the EG. For example, the D.C. 
Circuit has 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.'' 
Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433 (D.C. Cir. 1973). 
The court has further stated that the EPA may not adopt a standard in 
evaluating cost that would be ``exorbitant,'' \261\ ``greater than the 
industry could bear and survive,'' \262\ ``excessive,'' \263\ or 
``unreasonable.'' \264\ These formulations use reasonableness

[[Page 74819]]

in light of the statutory factors as the standard in evaluating cost, 
so that a control technology may be considered the ``best system of 
emission reduction . . . adequately demonstrated'' if its costs are 
reasonable (i.e., not exorbitant, excessive, or greater than the 
industry can bear), but cannot be considered the BSER if its costs are 
unreasonable. Similarly, in making the BSER determination, the EPA must 
evaluate whether a system of emission reduction is ``adequately 
demonstrated'' for the source category based on the physical 
possibility and technical feasibility of control. Under this construct, 
it naturally follows that most designated facilities within the source 
category should be able to implement the BSER at a reasonable cost to 
achieve the presumptive level of stringency, and RULOF will be 
applicable only for a subset of sources for which implementing the BSER 
would impose unreasonable costs or not be feasible due to unusual 
circumstances that are not applicable to the broader source category 
that the EPA considered when determining the BSER.\265\
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    \261\ Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. 
Cir. 1999).
    \262\ Portland Cement Ass'n v. EPA, 513 F.2d 506, 508 (D.C. Cir. 
1975).
    \263\ Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).
    \264\ Ibid.
    \265\ This construct is also supported by CAA section 111(d) use 
of the term ``establishing'' in directing states to create and set 
standards of performance. As previously described, ``standard of 
performance'' is defined under CAA section 111(a)(1) as reflecting 
the degree of emission limitation achievable through application of 
the BSER, which sets the initial parameters for development of the 
standards of performance by states. The statute does not provide 
that states may account for RULOF in ``establishing'' standards of 
performance in the first instance, but permits states to do so in 
``applying'' such standards to a particular source.
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    The RULOF provision we are proposing in this rule is consistent 
with how the EPA has approached RULOF in the implementing regulations 
previously. Subparts B and Ba both currently contain the same three 
circumstances for when states may account for RULOF, and reasonableness 
in light of the statutory criteria is an element of all three 
circumstances. Under those subparts as currently written, states may 
consider RULOF if they can demonstrate unreasonable cost of control, 
physical impossibility of control, or other factors that make 
application of a less stringent standard ``significantly more 
reasonable.'' 40 CFR 60.24(f), 40 CFR 60.24a(e). The EPA's proposal for 
EG OOOOc retains the first circumstance in whole and revises the second 
one to add ``technical infeasibility'' of installing a control as a 
situation where application of consideration of RULOF may be 
appropriate. The proposal for EG OOOOc further clarifies the third 
catch-all circumstance, which the first two circumstances also fall 
under, by specifying that states may consider RULOF to apply a less 
stringent standard if factors specific to a designated facility are 
fundamentally different from the factors considered in the 
determination of the BSER in EG OOOOc. The proposed third criteria 
provides parameters for states and the EPA in developing and assessing 
state plans, as this criterion was previously vague in the implementing 
regulations and potentially open-ended as to the circumstances under 
which states could consider RULOF.
    The ``fundamentally different'' standard, which undergirds all 
three circumstances, is also consistent with other variance provisions 
that courts have upheld for environmental statutes. For example, in 
Weyerhaeuser Co. v. Costle, 590 F.2d 1011 (D.C. Cir. 1978), the D.C. 
Circuit considered a regulatory provision promulgated under the Clean 
Water Act (CWA) that permitted owners to seek a variance from the EPA's 
national effluent limitation guidelines under CWA sections 301(b)(1)(A) 
and 304(b)(1). The EPA's regulation permitted a variance where an 
individual operator demonstrates a ``fundamental difference'' between a 
CWA section 304(b)(1)(B) factor at its facility and the EPA's 
regulatory findings about the factor ``on a national basis.'' Id. at 
1039. The court upheld this standard as ensuring a meaningful 
opportunity for an operator to seek dispensation from a limitation that 
would demand more of the individual facility than of the industry 
generally, but also noted that such a provision is not a license for 
avoidance of the Act's strict pollution control requirements. Id. at 
1035.
    For the reasons described in this section, the EPA is proposing 
RULOF provisions for purposes of EG OOOOc by: (1) Including the 
threshold requirements for consideration of RULOF; (2) adding 
requirements for calculating a less stringent standard accounting for 
RULOF; (3) adding requirements for consideration of communities most 
affected by and vulnerable to the health and environmental impacts from 
the designated facilities being addressed; and (4) adding requirements 
for the types of information and evidence the states must provide to 
support the invocation of RULOF in a state plan. The EPA solicits 
comment on the proposed provisions described in the following 
subsections, including the use of the BSER as a central tenet governing 
the invocation of the RULOF provision.
    The EPA also solicits comment about whether, instead of 
establishing firm requirements for the application of RULOF, the EPA 
should instead consider establishing a framework, consistent with the 
proposed requirements in the following discussion, pursuant to which 
state plans would be considered presumptively approvable. In this 
scenario, states would have certainty regarding what type of 
demonstration the EPA would find satisfactory as they develop their 
plans, but states could also submit an alternative RULOF demonstration 
for the EPA's consideration. In the latter case, states would bear the 
burden of proving to the EPA that they have proposed a satisfactory 
alterative analysis and standard, considering all factors relevant to 
addressing emissions from the source or sources at issue. The EPA also 
solicits comment on what different approaches might be appropriate for 
a state in applying RULOF to a particular source and that the EPA 
should consider in determining whether to finalize the provisions 
discussed below, either as requirements or as presumptions.
c. Threshold Requirements for Considering Remaining Useful Life and 
Other Factors
    Under the existing RULOF provision in subpart Ba, 40 CFR 60.24a(e), 
a state may only account for RULOF in applying a standard of 
performance provided that it makes a demonstration based on one of 
three criteria. These criteria are: (1) Unreasonable cost of control 
resulting from plant age, location, or basic process design; (2) 
physical impossibility of installing necessary control equipment; or 
(3) 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. But the existing version of this 
provision in subpart Ba provides no further guidance on what 
constitutes reasonableness or unreasonableness for these 
demonstrations. The EPA proposes this provision and clarifies it for 
purposes of EG OOOOc to require that in order to account for RULOF in 
applying a less stringent standard of performance to a designated 
facility, a state must demonstrate that the designated facility cannot 
reasonably apply the BSER to achieve the degree of emission limitation 
determined by the EPA because it entails: (1) An unreasonable cost of 
control resulting from plant age, location, or basic process design; 
(2) physical impossibility or technical infeasibility of installing 
necessary control equipment; or (3) other factors specific

[[Page 74820]]

to the facility (or class of facilities) that are fundamentally 
different from the factors considered in the establishment of the 
emission guidelines.\266\ The EPA proposes in EG OOOOc that the first 
criterion remains the same as under the existing RULOF provision in 40 
CFR 60.24a(e). For the second criterion, the EPA is proposing in EG 
OOOOc to add a reference to technical infeasibility, as a similar yet 
distinct factor from that of physical impossibility of control. 
Finally, the EPA is proposing in EG OOOOc to revise the third criterion 
to capture any circumstance at a specific designated facility that is 
fundamentally different from the factors the EPA considered in 
determining the BSER.
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    \266\ States may also account for RULOF when applying standards 
of performance to a class of designated facilities. For purposes of 
administrative efficiency, a state may be able to calculate a 
uniform standard of performance that accounts for RULOF using a 
single set of demonstrations to meet the proposed requirements 
described in this section if the group of sources has similar 
characteristics.
---------------------------------------------------------------------------

    The EPA proposes in EG OOOOc to require that, in order to 
demonstrate that a designated facility cannot reasonably meet the 
presumptive level of stringency based on one of these three criteria, 
the state must show that implementing the BSER is not reasonable for 
the designated facility due to fundamental differences between the 
factors the EPA considered in determining the BSER, such as cost and 
technical feasibility of control, and circumstances at the designated 
facility. Per the requirements of CAA section 111(a)(1), the EPA 
determines the BSER by first identifying control methods that it 
considers to be adequately demonstrated, and then determining which are 
the best systems by evaluating (1) the cost of achieving such 
reduction, (2) any non-air quality health and environmental impacts, 
(3) energy requirements, (4) the amount of reductions, and (5) 
advancement of technology. Accordingly, the state plan must show that 
there are fundamental differences between a designated facility and the 
EPA's BSER determination based on the EPA's consideration of any of 
these factors.
    For instance, if the state could demonstrate that the cost-per-ton 
was significantly higher at a specific designated facility than 
estimated by the EPA in the BSER analysis, and/or that a specific 
designated facility does not have adequate space to reasonably 
accommodate the installation, and/or that it is technically infeasible 
to comply with the presumptive standard based on source-specific 
technical barriers that are fundamentally different than those 
considered in the EPA's BSER determination, that designated facility 
may be evaluated for a less stringent standard because of the 
consideration of RULOF.
    However, states may not invoke RULOF based on minor, non-
fundamental differences. There could be instances where a designated 
facility may not be able to comply with the level of stringency 
required by EG OOOOc based on the precise metrics of the BSER 
determination but is able to do so within a reasonable margin. For 
example, the costs and cost effectiveness could be slightly higher than 
estimated by the EPA for the BSER for the presumptive standard, but 
that would not invoke RULOF. Similarly, there might also be instances 
where the EPA determines the BSER for a designated facility as a 
particular technology, but a particular designated facility does not 
currently have the capability to implement that technology, or it would 
be cost prohibitive to gain that capability. However, if that 
designated facility has the ability instead to reasonably install a 
different, non-BSER technology to achieve the presumptive level of 
stringency, the designated facility would not be eligible for a less 
stringent standard that accounts for RULOF.
    Following are a few illustrative examples. The EPA is proposing to 
determine the BSER for wet seal centrifugal compressors designated 
facility an emission standard of 3 scfm volumetric flow rate. As 
described in section IV.G of this preamble, the cost effectiveness of 
complying with the 3 scfm emission standard is estimated to be 
approximately $711 per ton of methane reduced for compressors in the 
transmission and storage segment. Therefore, under the proposed RULOF 
requirements for this EG, the state could evaluate the cost 
effectiveness of implementing the BSER for a particular wet seal 
centrifugal compressor in order to achieve the presumptive standard. As 
noted above, the first criterion a state may use to justify RULOF in 
applying a standard of performance is unreasonable cost of control 
resulting from plant age, location, or basic process design. If a state 
determined that for a centrifugal compressor affected facility in their 
state, the cost effectiveness was $71,000 per ton of methane removed, 
that would represent a valid demonstration of unreasonable cost of 
control. However, a slightly higher cost effectiveness (e.g., $1,000 
per ton, which is well within the range the EPA deems to be cost-
effective) may be representative of a minor difference that would not 
represent a valid demonstration for unreasonable cost. This example is 
only for illustrative purposes and should not be interpreted to 
represent the difference that must exist to demonstrate unreasonable 
cost of control (i.e., the cost effectiveness does not need to be two 
orders of magnitude higher than the presumptive standard to be 
considered unreasonable).
    By way of further example, for the pneumatic controller designated 
facility, the EPA determined that use of non-venting controllers is 
BSER. At sites without electrical power, compliance solutions include 
solar-powered controllers, a generator which powers electrical 
controllers or an instrument air system, capturing the emissions and 
routing them to a process, or installing self-contained controllers. 
There could be physical constraints that impact the installation of 
solar panels or a generator, and there may be technical infeasibility 
issues related to ability to route to a process or to use self-
contained controllers. If a state determined that it would be 
physically impossible and technically infeasible to install non-venting 
controllers at a designated facility given the size and physical 
constraints needed to install it, the lack of a process that can accept 
the gas, or operational conditions that would not support the use of a 
self-contained controller, this would represent a valid demonstration 
of physical impossibility or technical infeasibility of installing 
necessary control equipment.
    As a third example of how RULOF may not be used is in the case of 
the super-emitter response program. Upon notification of an emission 
event over 100 kg/hr, the program requires an owner/operator to do a 
root cause analysis to determine the source of the emissions event and 
either take corrective action or explain why no corrective action was 
warranted. Because it is not known what the source of the emissions 
event is prior to the root cause analysis, RULOF cannot be applied in 
any state plan to exempt an owner or operator from conducting this 
analysis. Moreover, the EPA anticipates it would generally be 
inappropriate for a designated facility with a less stringent standard 
due to RULOF to be permitted to have unintentional and continuing 
emissions events as high as 100 kg/hr such that the owner/operator 
would not need to take corrective action under the super-emitter 
response program.
    The EPA solicits comment on the proposal to require states to 
demonstrate, as a threshold matter when determining whether a state may 
account for RULOF in order to set a less

[[Page 74821]]

stringent standard, that the designated facility cannot reasonably 
apply the BSER to achieve the presumptive level of stringency 
determined by the EPA. The EPA further solicits comment on whether 
other considerations should inform the circumstances under which the 
EPA should permit RULOF to be used to set a less stringent standard for 
a particular designated facility. The EPA also discusses and solicits 
comments later in section V.B.3.g. on the types of information used to 
support a RULOF demonstration.
d. Calculation of a Standard Which Accounts for Remaining Useful Life 
and Other Factors
    If a state has made the proposed demonstration that accounting for 
RULOF is appropriate for a particular designated facility, the state 
may then apply a less stringent standard. The current RULOF provision 
in subpart Ba is silent as to how a less stringent standard should be 
calculated, raising the potential for inconsistent application of this 
provision across states and the potential for the imposition of a 
standard less stringent than what would be reasonably achievable by a 
designated facility. In order to fill this gap and ensure the integrity 
of EG OOOOc, the EPA is proposing several requirements that would apply 
for the calculation of a standard of performance that accounts for 
RULOF. The proposed requirements described in this section would 
provide a framework for the state's analysis in evaluating and 
identifying a less stringent standard, and in doing so would prevent 
the application of a standard that is less stringent than what is 
otherwise reasonably achievable by a particular designated facility.
    The EPA is first proposing in EG OOOOc to require that the state 
determine and include, as part of the plan submission, a source-
specific BSER for the designated facility. As described previously, the 
statute requires the EPA to determine the BSER by considering control 
methods that it considers to be adequately demonstrated, and then 
determining which are the best systems by evaluating: (1) The cost of 
achieving such reduction, (2) any non-air quality health and 
environmental impacts, (3) energy requirements, (4) the amount of 
reductions, and (5) advancement of technology. To be consistent with 
this statutory construct, the EPA proposes that in determining a less 
stringent BSER for a designated facility, a state must also consider 
all these factors in applying RULOF for that source. Specifically, the 
plan submission must identify all control technologies available for 
the source and evaluate the BSER factors for each technology, using the 
same metrics and evaluating them in the same manner as the EPA did in 
developing the EG using the five criteria noted above.\267\
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    \267\ To the extent that a state seeks to apply RULOF to a class 
of facilities that the state can demonstrate are similarly situated 
in all meaningful ways, the EPA proposes to permit the state to 
conduct an aggregate analysis of these factors for the entire class.
---------------------------------------------------------------------------

    We are further proposing that the standard must be in the same form 
(e.g., numerical rate-based emission standard) as required by the EG 
OOOOc presumptive standard. The EPA notes there may be cases where a 
state determines that a designated facility cannot reasonably implement 
the BSER but can instead reasonably implement another control measure 
to achieve the same level of stringency required by an EG. In such 
cases, the standard of performance that reflects the designated 
facility-specific BSER would be the same level of stringency as the 
degree of emission limitation achievable through application of the 
EPA's BSER.
    The EPA solicits comment on these proposed requirements for the 
calculation and form of the less stringent standard that accounts for 
remaining useful life and other factors. The EPA believes that the five 
identified BSER factors generally address all relevant information that 
states would reasonably consider in evaluating the emission reductions 
reasonably achievable for a designated facility. Moreover, the EPA 
considers that that these factors provide states with the discretion to 
weigh these factors in determining the BSER and establishing a 
reasonable standard of performance for the source. However, the EPA 
solicits comments on whether there are additional factors, not already 
accounted for in the BSER analysis, that the EPA should permit states 
to consider in determining the less stringent standard for an 
individual source. The EPA also solicits comments on whether we should 
consider these factors to be part of a presumptively approvable 
framework for applying a less stringent standard of performance, rather 
than requirements, and, if so, what different approaches states might 
use to evaluate and identify less stringent standards that the EPA 
should consider to be satisfactory in evaluating state plans that apply 
RULOF.
    The EPA also notes that CAA section 111(d) requires that state 
plans include measures that provide for the implementation and 
enforcement of a standard of performance. This requirement therefore 
applies to any standard of performance established by a state that 
accounts for RULOF. Such measures include monitoring, reporting, and 
recordkeeping requirements, as required by 40 CFR 60.25a, as well as 
any additional measures specified under EG OOOOc. In particular, any 
standard of performance that accounts for RULOF is also subject to the 
requirement under subpart Ba that the state plan submission include a 
demonstration that each standard is quantifiable, non-duplicative, 
permanent, verifiable, and enforceable. 40 CFR 60.27a(g)(3)(vi).
e. Contingency Requirements
    The EPA recognizes that a source's operations may change over time 
in ways that cannot always be anticipated or foreseen by the EPA, 
state, or designated facility. This is particularly true where a state 
seeks to rely on a designated facility's operational conditions, such 
as the source's remaining useful life or restricted capacity, as a 
basis for setting a less stringent standard. If the designated facility 
subsequently changes its operating conditions after the state applies a 
less stringent standard of performance, there is potential for the 
standard to not match what is reasonably achievable by a designated 
facility, resulting in forgone emission reductions and undermining the 
level of stringency set by EG OOOOc. For example, a state may seek to 
invoke RULOF for a designated facility located at a well site (e.g., 
storage vessel) during a time when oil prices are low. The market 
demand may prompt the owner or operator to shut the well site which may 
not have been anticipated by the BSER. The well site may be shut in for 
the duration of the compliance period required by an EG. Under this 
scenario, the state may be able to demonstrate that it is not 
reasonably cost effective for the designated facility to implement the 
BSER in order to achieve the presumptive level of stringency, and the 
state could set a less stringent standard of performance for this 
storage vessel designated facility. However, because market conditions 
are not a physical constraint on the designated facilities operations, 
it is possible that oil prices can increase in the future therefore 
causing the production demand to increase without any other legal 
constraint.
    The implementing regulations do not currently address this 
potential scenario. To address this issue, the EPA is proposing for 
purposes of EG OOOOc to add a contingency requirement to the RULOF 
provision that would require a state to include in its state plan a 
condition making a source's operating

[[Page 74822]]

condition, such as remaining useful life or restricted capacity, 
enforceable whenever the state seeks to rely on that operating 
condition as the basis for a less stringent standard. This requirement 
would not extend to instances where a state applies a less stringent 
standard on the basis of an unalterable condition that is not within 
the designated source's control, such as technical infeasibility, space 
limitations, water access, or subsurface reservoir and geological 
conditions. Rather, this requirement addresses operating conditions 
such as operation times, operational frequency, process temperature 
and/or pressure, flow rate, fuel parameters, and other conditions that 
are subject to the discretion and control of the designated facility.
    As previously discussed, the state plan submission must also 
include measures for the implementation and enforcement of a standard 
that accounts for RULOF. For standards that are based on operating 
conditions that a facility has discretion over and can control, the 
operating condition and any other measure that provides for the 
implementation and enforcement of the less stringent standard must be 
included in the plan submission and as a component of the standard of 
performance. For example, if a state applies a less stringent standard 
for a storage vessel designated facility on the basis that the storage 
vessel has less throughput than maximum capacity of the storage vessel 
(e.g., due to the current well production, or a state permit limit), 
the plan submission must include an enforceable requirement for the 
source to operate at or below that capacity factor, and include 
monitoring, reporting, and recordkeeping requirements that will allow 
the state, the EPA, and the public to ensure that the source is in fact 
operating at that lower capacity.
    The EPA notes there may be circumstances under which a designated 
facility's operating conditions change permanently so that there may be 
a potential violation of the contingency requirements approved as 
federally enforceable components of the state plan. For example, a 
storage vessel designated facility that was previously running at lower 
throughput now plans to run at a higher throughput full time, which 
conflicts with the federally enforceable state plan requirement that 
the facility operate at the lower throughput. To address this concern, 
a state may submit a plan revision to reflect the change in operating 
conditions. Such a plan revision must include a new standard of 
performance that accounts for the change in operating conditions. The 
plan revision would need to include a standard of performance that 
reflects the level of stringency required by EG OOOOc and meet all 
applicable requirements, or if a less stringent standard is still 
warranted for other reasons, the plan revision would need to meet all 
of the applicable requirements for considering RULOF.
    The EPA requests comment on the proposed contingency requirements 
to address the concern that a designated facility's operations may 
change over time in ways that do not match the original rationale for a 
less stringent standard.
f. Requirements Specific to Remaining Useful Life
    Remaining useful life is the one ``factor'' that CAA section 111(d) 
explicitly requires that the EPA permit states to consider in applying 
a standard of performance. The current RULOF provision generally allows 
for a state to account for remaining useful life to set a less 
stringent standard. However, the provision does not provide guidance or 
parameters on when and how a state may do so. Consistent with the 
principles described previously in this section, the EPA is proposing 
certain requirements for when a state seeks to apply a less stringent 
standard on grounds that a designated facility will retire in the near 
future.
    The EPA is proposing to require that in order to account for 
remaining useful life in setting a less stringent standard for a 
particular designated facility, the state plan must identify the 
source's retirement date and substantiate why this retirement date 
qualifies for the imposition of a less stringent standard. The state 
plan must include a demonstration of why the source's remaining useful 
life based on its retirement date reasonably warrants a less stringent 
standard and does not undermine the control objectives of the EG and 
CAA section 111(d) itself.
    This demonstration may take into account considerations in relation 
to the remaining useful life such as the time needed to purchase and 
install equipment required to comply, the time needed to develop a 
compliance plan and secure the services of specialized contractors to 
perform services required for compliance, the expected window of time 
needed to obtain approvals of outside agencies, the time needed to 
conduct any required community outreach or public hearings, as well as 
other potential factors.
    However, the EPA is proposing that one consideration must be 
addressed in every case to substantiate that the remaining useful life 
qualifies the imposition of a less stringent standard. That is, the 
state must demonstrate that the cost of control is unreasonable in 
relation to the retirement date.
    When the EPA determines a BSER, it considers cost and, in many 
instances, the EPA specifically considers annualized costs associated 
with payment of the total capital investment of the technology 
associated with the BSER. In the estimation of this annualized cost, 
the EPA assumes an interest rate and a capital recovery period, 
sometimes referred to as the payback period. For example, in the 
estimation of the annual costs for the installation of an instrument 
air system to power pneumatic controllers with compressed air a medium-
sized transmission and storage site, the EPA estimates that the total 
capital investment (equipment and installation) of the system would be 
$76,481. For the BSER analysis, the EPA assumed an interest rate of 
seven percent and a capital recovery period of 15 years. This means 
that the annual cost of recovering the initial capital investment 
including interest, was $8,397 per year for 15 years. The total annual 
cost includes this capital recovery cost plus the additional operation 
and maintenance cost of the equipment (additional beyond what would be 
required for a natural gas-driven controller system). For this example, 
the additional operation and maintenance cost was estimated to be 
$2,816 per year, resulting in a total annual cost of $11,213 and a cost 
effectiveness of $1,250 per ton of methane removed, which is a value 
within the range considered reasonable by the EPA.
    Therefore, for this example, the cost effectiveness is reasonable 
considering a capital recovery period, or payback period, of 15 years. 
If the remaining useful life was less than 15 years, the result could 
be a cost effectiveness that is outside of the range considered 
reasonable by the EPA. For example, consider a remaining useful life of 
six years. The resulting capital recovery cost would be $26,742 per 
year and total annual cost would be $29,196. This would yield a cost 
effectiveness of $1,834 per ton of methane removed, which would still 
be in the range considered reasonable by the EPA. Therefore, the state 
would not be able to claim that the costs were unreasonable for a 
remaining useful life of six years. However, if the remaining useful 
life were only two years, the capital recovery cost would be $70,502 
per year and the total annual cost would be $72,956. The cost 
effectiveness of this would be almost $4,600 per ton of methane 
removed, which is outside of

[[Page 74823]]

the range considered reasonable by the EPA. In this situation, this 
could potentially be used as part of a demonstration that may qualify 
the remaining useful life for the imposition of a less stringent 
standard.
    Note that this specific example is only for illustrative purposes. 
Specifically, for pneumatic controller designated facilities, there are 
compliance options (e.g., electric controllers) that are considerably 
less expensive than the installation of an instrument air system. A 
state would have to demonstrate unreasonable cost of control for each 
of the identified compliance options, not just one.
    The EPA proposes that the only cost factor that should be 
considered in a remaining useful life determination of cost 
unreasonableness is whether there is a significant capital investment 
required to design, purchase, and install equipment. A BSER based on 
compliance measures that do not require such upfront capital 
expenditures would have been demonstrated to have reasonable costs in 
the EPA's analysis for the presumptive standards. This would largely be 
the case if the affected facility operates for two years or 50 years. 
Therefore, the EPA does not believe that all types of designated 
facilities should be eligible for a determination of unreasonable costs 
associated with remaining useful life. Accordingly, the proposed rule 
would only allow that cost unreasonableness be considered in a state's 
demonstration that a source's remaining useful life based on its 
retirement date reasonably warrants a less stringent standard for the 
following types of designated facilities: oil wells with associated 
gas, storage vessels, pneumatic controllers, and pneumatic pumps. A 
cost unreasonableness determination would not be allowed for any other 
designated facility types. Note that this would not necessarily 
prohibit a state from making a demonstration for these other types of 
designated facilities, as some of the other factors mentioned above 
(e.g., time needed to develop a compliance plan and secure the services 
of specialized contractors to perform services required for compliance) 
could be relevant for such facilities. However, a state could not rely 
on unreasonable cost in determining that remaining useful life 
justifies a less stringent standard.
    The EPA recognizes that, even with the criteria outlined above, the 
result could be that different states could make demonstrations that 
result in different remaining useful life periods for the same types of 
designated facilities. In order to avoid this potential inequity, the 
EPA is requesting comment on whether EG OOOOc should include a single 
``outermost retirement date'' that would define the maximum length of 
time that would qualify for a designated facility to operate at a less 
stringent standard based on remaining useful life.
    As previously discussed, the EPA is proposing to require that when 
an operational condition is used as the basis for applying a less 
stringent standard, the state plan must include that condition as a 
federally enforceable requirement. Accordingly, if a state applies a 
less stringent standard by accounting for remaining useful life, the 
EPA is proposing to require that the state plan must include the 
retirement date for the designated facility as an enforceable 
commitment and include measures that provide for the implementation and 
enforcement of such commitment. For example, the state could adopt a 
regulation or enter into an agreed order requiring the designated 
facility to shut down by a certain date, and that regulation or agreed 
order should then be incorporated into the state plan. The state could 
also choose to incorporate the shutdown date into a permit, such as a 
preconstruction permit, and incorporate that permit into the state 
plan.
    The EPA is further proposing to require that the state plan impose 
a standard that applies to a designated facility until its retirement. 
This standard must reflect a reasonably achievable source specific BSER 
and be calculated as described in section IV of this preamble and 
section XII of the November 2021 proposal and supported by the 
demonstration described in 2021 TSD \268\ and the Supplemental TSD 
\269\ for this action. The EPA recognizes that, in some instances, a 
designated facility may intend to retire imminently after the 
promulgation of an EG, and in such cases it may not be reasonable to 
require any controls based on the source's exceptionally short 
remaining useful life. In the case of an imminently retiring source, 
the EPA is proposing that the state apply a standard no less stringent 
than one that reflects the designated facility's business as usual. 
This requirement equitably accommodates practical considerations 
without impermissibly exacerbating the impacts of the pollutant 
regulated under CAA section 111(d). The EPA generally expects that an 
``imminent'' retirement is one that is about to happen in the near 
term, e.g., within six months.
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    \268\ Document ID No. EPA-HQ-OAR-2021-0317-0166.
    \269\ Located at Docket ID No. EPA-HQ-OAR-2021-0317.
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    The EPA solicits comment on the proposed requirements specific to 
the consideration of remaining useful life as described in this 
section.
g. The EPA's Standard of Review of State Plans Invoking RULOF
    Under CAA section 111(d)(2), the EPA has the obligation to 
determine whether a state plan submission is ``satisfactory.'' This 
obligation extends to all aspects of a state plan, including the 
application of a less stringent standard of performance that accounts 
for RULOF. The proposed RULOF provision in EG OOOOc are intended to 
provide parameters not only for the development of CAA section 111(d) 
state plans, but for the EPA to evaluate the approvability of such 
plans. The EPA is proposing the following requirements to further 
bolster the RULOF provision and to facilitate the EPA's review of a 
state plan to determine whether the plan implementing the RULOF 
provision is ``satisfactory.'' As an initial matter, the EPA proposes 
to explicitly require that the state must carry the burden of making 
the demonstrations required under the RULOF provision. States carry the 
primary responsibility to develop plans that meet the requirements of 
CAA section 111(d) and therefore have the obligation to justify any 
accounting for RULOF that they invoke in support of standards less 
stringent than those provided by EG OOOOc. While the EPA has discretion 
to supplement a state's demonstration, the EPA may also find that a 
state plan's failure to include a sufficient RULOF demonstration is a 
basis for concluding the plan is not ``satisfactory'' and therefore 
disapprove the plan.
    The EPA is further proposing that for the required demonstrations, 
the state must use information that is applicable to and appropriate 
for the specific designated facility, and the state must show how 
information is applicable and appropriate. As RULOF is a source-
specific determination, it is appropriate to require that the 
information used to justify a less stringent standard for a particular 
designated facility be applicable to and appropriate for that source. 
The EPA anticipates that in most circumstances, site-specific 
information will be the most applicable and appropriate to use for 
these demonstrations and proposes to require site-specific information 
where available. In some instances, site-specific information may not 
be available, and a state may instead be able to use general 
information about the Crude Oil and Natural Gas source

[[Page 74824]]

category to evaluate a particular designated facility. In such cases, 
the state plan submission must provide both the general information and 
a clear assessment of how the information is applicable to and 
appropriate for the designated facility. The use of general information 
must also be consistent with and supportive of the overall assessment 
and conclusions regarding consideration of RULOF for the specific 
designated facility.
    Finally, the EPA proposes to require that the information used for 
a state's demonstrations under the new RULOF provisions must come from 
reliable and adequately documented sources, which presumptively include 
the following: EPA sources and publications, permits, environmental 
consultants, control technology vendors, and inspection reports. 
Requiring the use of such sources will help ensure that an accounting 
of RULOF is premised on legitimate, verifiable, and transparent 
information. The EPA solicits comment on the proposed list of 
information sources and whether other sources should be considered as 
reliable and adequately documented sources of information for purposes 
of the RULOF demonstration, including but not limited to reliable and 
adequately documented sources of cost information. \270\
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    \270\ The EPA acknowledges there may be reliable and adequately 
documented sources of information other than those described in this 
section. The EPA encourages states to consult with their Regional 
Offices if there are questions about whether a particular source of 
information would meet the applicable requirements.
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    These requirements will aid both the EPA in evaluating whether 
RULOF has been appropriately accounted for, and the public in 
commenting on the EPA's proposed action on a state plan that includes a 
less stringent standard on the basis of RULOF. The EPA solicits comment 
on the proposed requirements described in this section regarding the 
EPA's standard of review for state plans that invoke consideration of 
RULOF.
h. Consideration of Impacted Communities
    CAA section 111(d) does not specify what are the ``other factors'' 
that the EPA's regulations should permit a state to consider in 
applying a standard of performance. The EPA interprets this as 
providing discretion for the EPA to identify the appropriate factors 
and conditions under which the circumstance may be reasonably invoked 
in establishing a standard less stringent than the EG. Additionally, 
CAA section 111(d)(2)'s requirement that the EPA determine whether a 
state plan is ``satisfactory'' applies to such plan's consideration of 
RULOF in applying a standard of performance to a particular facility. 
Accordingly, the EPA must determine whether a plan's consideration of 
RULOF is consistent with section 111(d)'s overall health and welfare 
objectives. While the consideration of RULOF can be warranted to apply 
a less stringent standard of performance to a particular facility, such 
standards have the potential to result in disparate health and 
environmental impacts to communities most affected by and vulnerable to 
impacts from the designated facilities being addressed by the state 
plan. Those communities could be put in the position of bearing the 
brunt of the greater health and environmental impacts resulting from 
that source implementing less stringent emission controls than would 
otherwise have been required pursuant to the EG. The EPA finds that a 
lack of consideration to such potential outcomes would be antithetical 
to the public health and welfare goals of CAA section 111(d) and the 
CAA generally.
    In order to address the potential exacerbation of health and 
environmental impacts to vulnerable communities as a result of applying 
a less stringent standard, the EPA is proposing in EG OOOOc to require 
states to consider such impacts when applying the RULOF provision to 
establish those standards. The EPA is proposing to require that, to the 
extent a designated facility would qualify for a less stringent 
standard through consideration of RULOF, the state, in calculating such 
standard, must consider the potential health and environmental impacts 
on communities most affected by and vulnerable to the impacts from the 
designated facility considered in a state plan for RULOF provisions. 
These communities will be identified by the state as pertinent 
stakeholders under the proposed meaningful engagement requirements 
described in section V.B.6 of this preamble.\271\
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    \271\ Pursuant to the proposed meaningful engagement 
requirements that states must complete prior to the submittal of 
their state plans, states must identify pertinent stakeholders and 
meaningfully engage with such pertinent stakeholders, including 
communities most affected by and vulnerable to the impacts of the 
plan.
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    The EPA proposes to require that state plan submissions seeking to 
invoke RULOF for a source must identify where and how a less stringent 
standard impacts these communities. In evaluating a RULOF option for a 
facility, states should describe the health and environmental impacts 
anticipated from the application of RULOF for such communities, along 
with any feedback the state received during meaningful engagement 
regarding its draft state plan submission, including on any standards 
of performance that consider RULOF. Additionally, to the extent there 
is a range of options for reasonably controlling a source based on 
RULOF, the EPA is proposing that in determining the appropriate 
standard of performance, states should consider the health and 
environmental benefits to the communities most affected by and 
vulnerable to the impacts from the designated facility considered in a 
state plan for RULOF provisions, and also provide in the state plan 
submission a summary of the results that depicts the impacts to those 
communities. This requirement to consider the health and environmental 
impacts in any standard of performance taking into account RULOF is 
consistent with the definition of ``standard of performance'' in CAA 
section 111(a)(1). This definition requires the EPA to take into 
account health and environmental impacts in determining the BSER. As 
described in this section, if a designated facility qualifies for a 
less stringent standard based on RULOF, the EPA is proposing the state 
plan must identify a source-specific BSER based on the same factors and 
metrics the EPA considered in determining the BSER in the EG. 
Therefore, state plans must consider health and environmental impacts 
in determining a source-specific BSER informing a RULOF standard, just 
as the EPA is statutorily required to take into account these factors 
in making its BSER determination. See section IV.D.1.b.III for an 
example of the environmental impacts assessed for the EPA's proposed 
BSER determination for pneumatic controllers.
    As an example, the state plan submission could include a 
comparative analysis assessing potential controls on a designated 
facility and the corresponding potential benefits to the identified 
communities in controlling the designated facility. If the comparative 
analysis shows that a designated facility could be controlled at a 
certain cost threshold higher than required under the EPA's proposed 
revisions to the RULOF provision, and such control benefits the 
communities that would otherwise be adversely impacted by a less 
stringent standard, the state in accounting for RULOF could choose to 
use that cost threshold to apply a standard of performance.\272\

[[Page 74825]]

Given that states have the discretion rather than mandate to consider 
RULOF in applying a standard of performance under CAA section 111(d), 
it is reasonable for states to consider the potential impacts to 
communities most affected by and vulnerable to the impacts from a 
particular designated facility in calculating the level of stringency 
for such standard.
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    \272\ As previously described, CAA section 111(d) gives states 
the discretion to consider RULOF for a particular source and are not 
required to do so. States thus have the authority to choose to 
impose a more stringent standard, including the presumptive 
standard, than would be permissible under RULOF for other reasons, 
e.g. based on consideration of communities other than identified 
impacted communities.
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    Additionally, under CAA section 111(d)(2)(B), the EPA has the 
authority to prescribe a Federal plan promulgating a standard of 
performance for designated facilities located in a state that fails to 
submit a satisfactory plan. Consistent with the statute's mandate for 
the EPA's regulations under CAA section 111(d) to permit states to 
account for RULOF, this provision further directs that the EPA 
``shall'' take into account RULOF in promulgating standards of 
performance for the source category under the Federal plan. Therefore, 
because the statute uses the same ``other factors'' phrasing in both 
CAA sections 111(d)(1) governing state plans and 111(d)(2) governing 
Federal plans, the EPA proposes in EG OOOOc to require that impacts to 
communities most affected by and vulnerable to the impacts from 
designated facilities be considered in both the state and Federal plan 
contexts when accounting for RULOF.
    The EPA solicits comment on the proposed requirements described in 
this section for consideration of vulnerable communities in the context 
of RULOF.
i. Authority To Apply More Stringent Standards as Part of the State 
Plan
    In the November 2021 proposal, the EPA proposed that states are 
authorized to include in their state plans, and the EPA is authorized 
to approve, requirements that are more stringent than the EG under the 
authority of CAA section 116, as interpreted by the Court in Union 
Electric v. EPA, 27 U.S. 246, (1976). 86 FR 63251. The EPA is now 
proposing that under CAA section 111(d), consistent with the authority 
conferred by CAA section 116, states may consider RULOF to include more 
stringent standards of performance in their state plans.
    The current RULOF provision in subpart Ba under 40 CFR 60.24a(e) 
governs instances where states seek to apply a less stringent standard 
of performance to a particular designated facility. In promulgating 
this provision, the EPA received comments contending that if states may 
consider factors that justify less stringent standards, they must also 
be permitted to consider factors that would justify greater stringency 
than required by an EG, such as more expeditious compliance obligations 
or the retirement of a source. EPA's Responses to Public Comments on 
the EPA's Proposed Revisions to Emission Guideline Implementing 
Regulations at 56 (Docket ID No. EPA-HQ-OAR-2017-0355-26740) (July 8, 
2019). In response to these comments, the EPA explained that it 
interpreted the statutory RULOF provision as intended to authorize only 
standards of performance that are less stringent than the presumptive 
level of stringency required by a particular EG. Id. at 57. The EPA has 
reevaluated its prior interpretation and is now proposing for purposes 
of EG OOOOc to interpret that the statute authorizes the EPA to permit 
states to consider other factors that justify application of a more 
stringent standard to a particular source than required by an EG. See 
FCC v. Fox Television Stations, Inc., 556 U.S. 502 (2009). The EPA's 
rationale for its revised interpretation and proposal is as follows.
    As described previously, while standards of performance must 
generally reflect the presumptive level of stringency identified in the 
EG, CAA section 111(d) also requires the EPA to permit states to ``take 
into consideration, among other factors, the remaining useful life'' in 
applying a standard of performance to a particular designated facility. 
Aside from the explicit reference to remaining useful life, the statute 
is silent as to what the ``other factors'' are that states may consider 
in applying a standard of performance. It also silent as to whether the 
``standard of performance'' to be ``appl[ied]'' to a ``particular 
source'' must be a weaker or stronger standard--the only inference that 
can be drawn from the statutory language is that RULOF may be used to 
apply a different standard. Therefore, the EPA may reasonably interpret 
this ambiguity both as to what the ``other factors'' are that states 
may use to apply a standard of performance to a particular source, and 
how such consideration may affect the stringency of such standard. 
Accordingly, the EPA reasonably interprets this phrase as authorizing 
states to consider other factors in exercising their discretion to 
apply a more stringent standard to particular a source. This is a 
reasonable interpretation of the statute because if Congress intended 
the RULOF provision to be used only to allow states to apply less 
stringent standards, it would have clearly specified that its intent or 
enumerated ``other factors'' that are appropriate for relaxing the 
stringency of a standard. The statute's explicit reference to remaining 
useful life shows that if there were factors that Congress specifically 
wanted the EPA to allow or disallow states to consider, it knew how to 
expressly make its intent clear in the RULOF provision.
    In addition to finding that the statute does not preclude the EPA's 
reasonable interpretation of the statutory RULOF provision as described 
above, the EPA has reevaluated the bases for its prior interpretation 
that states may only consider RULOF to apply a less stringent standard 
and determined those bases were flawed. In making its prior 
interpretation, the EPA noted that the new regulatory RULOF provision 
under subpart Ba at 40 CFR 60.24a(e) was substantively similar to the 
variance provision under subpart B, which authorizes the use of other 
factors that ``make application of a less stringent standard or final 
compliance time significantly more reasonable.'' 40 CFR 60.24(f)(3). 
The EPA reasoned that because the variance provision under subpart B is 
similar to and predated Congress's addition of the statutory RULOF 
provision to CAA section 111(d) as part of the 1977 CAA Amendments, 
``Congress effectively ratified the EPA's implementing regulations' 
clear construct that remaining useful life and other factors are only 
relevant in the context of setting less stringent standards.'' EPA's 
Responses to Public Comments on the EPA's Proposed Revisions to 
Emission Guideline Implementing Regulations at 57 (Docket ID# No. EPA-
HQ-OAR-2017-0355-26740) (July 8, 2019). The EPA has closely reexamined 
the variance provision under subpart B and the RULOF provision under 
CAA section 111(d) and does not find that these provisions support the 
proposition that Congress clearly ratified the aspect of the variance 
provision in subpart B allowing states to apply only less stringent 
standards under certain circumstances. There are notable differences 
between the subpart B variance provision and the CAA section 111(d) 
RULOF provision that indicate Congress did not intend to incorporate 
and ratify all aspects of the EPA's regulatory approach when amending 
CAA section 111(d) in 1977. Particularly, for pollutants found to cause 
or contribute to endangerment of public health, subpart B allows states 
to apply a less stringent standard under

[[Page 74826]]

certain circumstances unless the EPA provides otherwise in a specific 
EG for a particular designated facility or class of facilities. 40 CFR 
60.24(c), (f). Subpart B places no similar exception for states in 
authorizing them to seek a variance for a standard addressing a 
pollutant for which the EPA has made a welfare-based, but not public 
health-based, endangerment finding under 111(b)(1)(A). 40 CFR 60.24(d). 
By contrast, the statutory RULOF provision does not make a similar 
distinction between public health and welfare-based pollutants, which 
the EPA itself acknowledged in promulgating the regulatory RULOF 
provision in subpart Ba. 84 FR 32570 (July 8, 2019). Therefore, the EPA 
cannot clearly ascertain whether the statutory RULOF provision ratified 
the variance provision under subpart B, given that certain key elements 
of the latter are not present in the former. There is nothing in CAA 
section 111(d) or the legislative history that suggests Congress 
enacted the statutory RULOF provision by ratifying certain elements of 
the regulatory variance provision in subpart B but not others.
    Additionally, in taking its prior position that states may only 
consider RULOF to apply a less stringent standard, the EPA asserted 
that the legislative history of the 1977 CAA Amendments supported its 
interpretation. The EPA highlighted the following statement in the 
House conference report adopting the amendment to add the statutory 
RULOF provision: ``The section also makes clear that standards adopted 
for existing sources under section 111(d) of the Act are to be based on 
available means of emission control (not necessarily technological) and 
must, unless the state decides to be more stringent, take into account 
the remaining useful life of the existing sources.'' H.R. Conf. Rep. 
No. 94-1742, (Sep. 30, 1976), 1977 CAA Legis. Hist. at 88. Based on 
this statement, the EPA found that the caveat that states have the 
choice to not invoke the RULOF provision and instead ``be more 
stringent'' suggests that considering RULOF is only intended to allow a 
state to make a standard less stringent. The EPA now finds that its 
prior reliance on this legislative history was flawed. The cited 
statement only speaks to remaining useful life, which is a factor that 
inherently suggests a less stringent standard, but it is completely 
silent as to the ``other factors'' the statute references. Thus, there 
is no indication that Congress intended to limit the ``other factors'' 
that states may apply in developing their plans only to permit less 
stringent, and not also more stringent standards. Rather, the cited 
statement explicitly acknowledges that states may choose to ``be more 
stringent'', which supports the EPA's interpretation of the statute to 
permit states to consider other factors to set standards more stringent 
than the degree of emission limitation achievable through application 
of the BSER.
    Interpreting the statutory RULOF provision as authorizing states to 
apply a more stringent standard of performance to a particular source 
is also consistent with the purpose and structure of CAA section 
111(d). CAA section 111(d) clearly contemplates cooperative federalism, 
where states bear the obligation to establish standards of performance. 
Nothing under CAA section 111(d) suggests that the EPA has the 
authority to preclude states from determining that it is appropriate to 
regulate certain sources within their jurisdiction more strictly than 
otherwise required by federal requirements. To do so would be arbitrary 
and capricious in light of the overarching purpose of CAA section 
111(d), which is to require emission reductions from existing sources 
for certain pollutants that endanger public health or welfare. It is 
inconsistent with the purpose of CAA section 111(d) and the role it 
confers upon states for the EPA to constrain them from further reducing 
emissions that harm their citizens, and the EPA does not see a 
reasonable basis for doing so.
    Other factors states may wish to account for in applying a more 
stringent standard than required under an EG include, but are not 
limited to, early retirements, effects on local communities, and 
availability of control technologies that allow a source to achieve 
greater emission reductions. However, the EPA cannot anticipate each 
and every factor under which a state may seek to apply a more stringent 
standard. Therefore, the EPA will evaluate on a case-by-case basis the 
inclusion of a more stringent standard in a state plan addressing EG 
OOOOc. The EPA is also proposing to require that states seeking to 
apply a more stringent standard of performance based on other factors 
must adequately demonstrate that the different standard is in fact more 
stringent than the presumptive level of stringency. Such standard of 
performance must meet all applicable statutory and regulatory 
requirements, including that it is adequately demonstrated,\273\ and 
the state plan must include measures that provide for the 
implementation and enforcement of the standard as with any standard of 
performance under CAA section 111(d).
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    \273\ The EPA is not proposing to require the state to conduct a 
source-specific BSER analysis for purposes of applying a more 
stringent standard, as the EPA proposes to require for application 
of a less stringent standard. So long as the standard will achieve 
equivalent or better emission reductions than required by EG OOOOc, 
the EPA believes it is appropriate to defer to the state's 
discretion to, e.g., choose to impose more costly controls on an 
individual source.
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    For the reasons described in this section, the EPA proposes to 
permit states to consider factors which justify applying a standard of 
performance that is more stringent than required under an EG OOOOc.
    Therefore, for purposes of EG OOOOc, per the authority of CAA 
sections 111(d) and 116, the EPA proposes to permit states to include 
more stringent standards of performance in their plans and that the EPA 
must approve and render such standards as federally enforceable, so 
long as the minimum requirements of the EG and subpart Ba are met.\274\ 
The EPA solicits comment on its proposal as described in this section.
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    \274\ The EPA notes that its authority is constrained to 
approving measures which comport with applicable statutory 
requirements. For example, CAA section 111(d) only contemplates that 
state plans would include requirements for designated facilities 
regulated by a particular EG; therefore, the EPA concludes that CAA 
section 116 does not provide it with the authority to approve and 
render federally enforceable measures on entities other than those 
on designated facilities.
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4. Providing Measures That Implement and Enforce Such Standards
    As described in the November 2021 proposal, the EPA proposed to 
require that state plans must also include compliance schedules for the 
presumptive standards including where states choose to account for 
RULOF, methods employed to implement and enforce the presumptive 
standards such that the EPA can review and identify measures that 
assure transparent and verifiable implementation, and states must 
include appropriate monitoring, reporting, and recordkeeping 
requirements to ensure that state plans adequately provide for the 
implementation and enforcement of the presumptive standards.\275\ The 
EPA is proposing to supplement the November 2021 proposal by clarifying 
that states maintain the same monitoring, reporting, and recordkeeping 
requirements, or equivalent requirements as described in EG OOOOc for 
presumptive standards that states adopt in their plans. The EPA further 
clarifies that where a state plan adopts standards of performance that

[[Page 74827]]

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 and 
must be determined to be equivalent as described in Section V.B.2. 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.
---------------------------------------------------------------------------

    \275\ 86 FR 63252 (November 15, 2021).
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5. Emissions Inventories
    In the November 2021 proposal the EPA discussed that the 
implementing regulations at 40 CFR 60.25a contain generally applicable 
requirements for emission inventories, source surveillance, and 
reports. 86 FR 63253 (November 16, 2021). 40 CFR 60.25a(a) requires 
that state plans shall include an inventory of all designated 
facilities, including emission data for the designated pollutants. This 
provision further requires 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. However, due to the very large number of existing oil and 
natural gas sources,\276\ and the frequent change of configuration and/
or ownership, the EPA recognized 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 solicited comment on whether to supersede the requirements of 40 
CFR 60.25a(a) for purposes of this EG.\277\
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    \276\ In the U.S. the EPA has identified over 15,000 oil and gas 
owners and operators, around 1 million producing onshore oil and gas 
wells, about 5,000 gathering and boosting facilities, over 650 
natural gas processing facilities, and about 1,400 transmission 
compression facilities.
    \277\ 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).
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    State commenters generally support superseding the implementing 
regulations and agree that states should be able to document impacted 
sources differently than other CAA section 111(d) plans.\278\ While 
some state commenters have state inventories, others confirmed the 
EPA's understanding that some states do not have comprehensive tracking 
systems for a designated facility inventory and associated 
emissions.\279\ Some commenters discussed that the development of such 
an inventory would be resource intensive with little benefit.\280\ The 
State of Colorado referenced their 2020 leak inspection reporting 
program which suggests there are over 15,000 well production facilities 
in the state and the State of West Virginia estimates over 54,000 
natural gas and over 10,000 crude oil producing wells in the 
state.\281\ Both states recognize that each well production facility 
would represent a much greater number of individual designated 
facilities. The State of West Virginia further described the complexity 
of inventory development given not only the vast number of sources, but 
also the frequent change of configurations and ownership within the 
industry. These points were echoed by the State of Texas which also 
provided an estimate of the number of production wells in the state, 
however, they noted that unless a state-wide equipment inventory is 
conducted the number of designated facilities is unclear.\282\ Multiple 
state commenters support the EPA allowing states to leverage existing 
inventories and emissions data, even if that data might not be fully 
aligned with the designated facilities in the EG.\283\
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    \278\ The EPA received several comments on this topic. A 
sampling of these comments is cited in footnotes in this section. 
See Document ID Nos. EPA-HQ-OAR-2021-0317-0769, EPA-HQ-OAR-2021-
0317-0775.
    \279\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0832-A2, EPA-HQ-
OAR-2021-0317-0722.
    \280\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0200.
    \281\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0775, EPA-HQ-
OAR-2021-0317-0424.
    \282\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0419.
    \283\ See Document ID Nos. EPA-HQ-OAR-2021-0317-1267.
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    For purposes of this EG, the EPA does not believe that the 
inventory and detailed emissions data required under 40 CFR 60.25a(a) 
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. For example, the emissions inventory data 
could be derived from the GHGRP, which collects GHG emissions and 
activity data annually from applicable facilities conducting petroleum 
and natural gas systems activities. Facilities use uniform methods 
prescribed by the EPA to calculate emissions for applicable source 
types, and the EPA conducts a multi-step verification process to ensure 
reported data are accurate, complete, and consistent. Reported data are 
made available to the public through several portals accessible via the 
EPA's website. The emissions and activity data reported to the GHGRP 
can be leveraged to develop standards of performance. While the EPA 
recognizes that the GHGRP includes a reporting threshold and that GHGRP 
facility definitions and emission factors might not be fully aligned 
with the designated facilities in the EG, the GHGRP data represent the 
same general type of inventory information as the inventory and 
detailed emissions data required under 40 CFR 60.25a(a). In addition, 
the EPA does not think it reasonable to burden states to derive 
information from GHGRP, which the EPA already has, only to resubmit it 
to the Agency. The EPA notes that emissions inventory data used to 
develop standards of performance could also be derived from other 
available existing inventory information available to the state. 
Therefore, in order to avoid the potential burden that could be imposed 
by applying 40 CFR 60.25a(a) as written to this EG, and potential 
burden and duplicative information collection imposed by requiring 
states to use other inventories such as GHGRP, the EPA proposes to 
supersede the requirements of 40 CFR 60.25a(a) for purposes of this EG, 
so that state plans are not required to include an inventory and 
emissions data as described under this provision.
6. Meaningful Engagement
    In the November 2021 proposal, the EPA proposed and solicited 
comment on requiring states to perform early outreach and meaningful 
engagement with overburdened and underserved communities during the 
development process of their state plan pursuant to EG OOOOc.\284\ The 
fundamental purpose of CAA section 111 is to reduce emissions from 
certain stationary sources that cause, or significantly contribute to, 
air pollution which may reasonably be anticipated to endanger public 
health or welfare. Therefore, a key consideration in the state's 
development of a state plan, in any significant plan revision,\285\ and 
in the EPA's development of a Federal plan pursuant to an EG 
promulgated under CAA section 111(d) is the potential impact of the 
proposed plan requirements on public health and welfare. A robust and 
meaningful public participation process during plan development is 
critical to ensuring that the full range of these impacts are 
understood and considered. The EPA received numerous comments from 
states supporting the proposed

[[Page 74828]]

requirements for meaningful engagement, providing suggestions based on 
their own experience and initiatives, while requesting that the EPA 
provide specificity around meaningful engagement and examples of 
satisfactory engagement. The EPA also hosted two discussions with 
representatives of state and local air agencies to hear more about 
their perspectives on meaningful engagement. The Agency held a similar 
meeting with communities, tribes, and small businesses to hear their 
views on meaningful engagement.
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    \284\ See 86 FR 63254 (November 15, 2021).
    \285\ Significant state plan revision includes, but is not 
limited to, any revision to standards of performance or to measures 
that provide for the implementation or enforcement of such 
standards.
---------------------------------------------------------------------------

    Many stakeholders support robust public engagement, especially with 
communities most affected by and vulnerable to the impacts of the state 
plan, and some highlight how this type of public engagement aligns with 
their commitment to EJ.\286\ State commenters also encouraged the EPA 
to allow for flexibility to craft plans to the unique economic and 
demographic features of each state.\287\ Some states and industry 
commenters question the EPA's authority to require states to conduct 
meaningful engagement and seek guidance on alternative procedures for 
meaningful engagement.\288\ Other state commenters indicate that states 
already take EJ initiatives into consideration and some say additional 
efforts would be redundant and share concern about adequate resources 
to conduct meaningful engagement.\289\ State commenters generally 
advocate for the EPA to provide examples of the types of engagement 
that will be approvable and seek additional guidance. Industry 
commenters expressed commitment to support constructive interactions 
between industry, regulators, and surrounding communities and 
populations that may be disproportionately impacted.\290\ Some industry 
and state commenters express concern that the meaningful engagement 
requirement could cause disapproval of a state plan if the EPA fails to 
provide a definition for meaningful engagement with clear parameters 
and examples of adequate engagement.\291\
---------------------------------------------------------------------------

    \286\ The EPA received several comments on this topic. A 
sampling of these comments are cited in footnotes in this section. 
See Document ID Nos. EPA-HQ-OAR-2021-0317-0581, EPA-HQ-OAR-2021-
0317-0808-A1, EPA-HQ-OAR-2021-0317-0921, EPA-HQ-OAR-2021-0317-0938, 
EPA-HQ-OAR-2021-0317-0814, EPA-HQ-OAR-2021-0317-0832-A2, EPA-HQ-OAR-
2021-0317-0727, EPA-HQ-OAR-2021-0317-0775, and EPA-HQ-OAR-2021-0317-
1267.
    \287\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0832-A2 and EPA-
HQ-OAR-2021-0317-0581.
    \288\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0727, EPA-HQ-
OAR-2021-0317-0921, EPA-HQ-OAR-2021-0317-0938, EPA-HQ-OAR-2021-0317-
0921, EPA-HQ-OAR-2021-0317-0763, EPA-HQ-OAR-2021-0317-0722.
    \289\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0775 and EPA-HQ-
OAR-2021-0317-0727.
    \290\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0808-A1, EPA-HQ-
OAR-2021-0317-0445, EPA-HQ-OAR-2021-0317-0819, and EPA-HQ-OAR-2021-
0317-0456.
    \291\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0921 and EPA-HQ-
OAR-2021-0317-0938.
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    State commenters offer an array of helpful suggestions based on 
their own experience and initiatives. New Mexico, for example, agreed 
with the EPA that requiring states to share information and solicit 
input from stakeholders at critical junctures during plan development 
will ensure communities have abundant opportunities to participate in 
the plan development process.\292\ New Mexico further agreed with the 
EPA's proposal to give the reasonable notice requirement additional and 
separate meaning from ``public hearing'' to ensure the public has 
reasonable notice of relevant information, as well as the opportunity 
to participate in the state plan development.
---------------------------------------------------------------------------

    \292\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0832-A2.
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    New Mexico discusses that in addition to using traditional 
communication technologies, even with potential barriers involving 
accessibility of technologies (e.g., video conferencing, social media, 
and smart phone applications), these new technologies should also be 
utilized during the meaningful engagement process and they specifically 
ask the EPA to permit both new and traditional communication 
technologies to qualify as a means to conduct meaningful public 
engagement. New Mexico also suggests that states, local governments, 
community organizations, and other stakeholders may find it helpful to 
create organized groups that can help address interstate air quality 
issues. For example, they participate in the Four Corners Air Quality 
Group, which could serve as a model for such coordination. New Mexico, 
along with the Navajo Nation, Colorado, Arizona, and Utah meet 
regularly to address common air quality issues in the region. The Four 
Corners Air Quality Group also includes a variety of different 
stakeholders including community members and organizations and industry 
leaders. The goals and functions of any cross-border groups can, and 
should, be crafted to the unique needs of the area(s) in which they 
serve.
    States and Cities provided other examples of strategies for states 
to consider.\293\ They first suggest targeting special notice, by mail, 
of public participation opportunities to residents and schools within a 
certain radius from regulated oil and natural gas facilities. Their 
second suggestion includes hosting a series of public meetings or 
workshops to provide background on the purpose of the state plans, the 
process for developing the plans, and the public comment and hearing 
process. Third, they suggest assuring that those public meetings, 
workshops, and hearings are held at times that are convenient for 
members of the affected community, that translation services are 
available at such events, and that there are options for participating 
via phone or videoconference. Fourth, they recommend ensuring that any 
public meeting, workshop, hearing, or other format for gathering input 
are safe spaces and that participation does not endanger community 
members because of immigration or employment status. Fifth, they 
suggest providing information on a public website and in hardcopy at an 
accessible location within the community, such as a public library or 
school. Lastly, they agree that the state plan submission would need to 
describe and report on the engagement conducted which would be 
evaluated as part of the state plan completeness determination. 
Commenters also seek additional guidance on how states could go about 
making public meetings or workshops safe spaces for undocumented 
members of overburdened or underserved communities. Similarly, 
commenters ask if the EPA could specify that information about the 
rulemaking to be shared at a public meeting or workshop must be 
translated in communities with linguistic barriers by the EPA's duties 
under Title VI the Civil Rights Act.
---------------------------------------------------------------------------

    \293\ See Document ID Nos. EPA-HQ-OAR-2021-0317-1267.
---------------------------------------------------------------------------

    The EPA previously proposed in EG OOOOc to include certain 
meaningful engagement in addition to the requirements for notice and 
public hearing. The notice and public hearing requirements in 40 CFR 
60.23a(c)-(f) require the states to conduct one or more public hearings 
prior to the adoption of any plan. The states are to provide 
notification to the public by prominent advertisement to the public of 
the date, time, and place of the public hearing, 30 days prior to the 
date of such hearing, and the advertisement requirement may be 
satisfied through the internet. Id. at (d).
    The EPA recognizes that a fundamental purpose of the Act's notice 
and public hearing requirements is for all affected members of the 
public, and not just a particular subset, to participate in pollution 
control planning processes that impact their health and

[[Page 74829]]

welfare.\294\ Accordingly, in order for there to be a meaningful 
opportunity for the public to participate in hearings on CAA section 
111(d) state plans, the notice of such hearings must be reasonably 
adequate in its ability to reach affected members of the public. Many 
states provide for notification of public engagement through the 
internet, however there cannot be a presumption that such notification 
is adequate in reaching all those who are impacted by a CAA section 
111(d) state plan and would benefit the most from participating in a 
public hearing. For example, data shows that as many as 30 million 
Americans do not have access to broadband infrastructure that delivers 
even minimally sufficient speeds, and that 25 percent of adults ages 65 
and older report never going online.\295\ Examples of prominent 
advertisement for a public hearing, in addition to through the 
internet, may include notice through newspapers, libraries, schools, 
hospitals, travel centers, community centers, places of worship, gas 
stations, convenience stores, casinos, smoke shops, Tribal Assistance 
for Needy Families offices, Indian Health Services, clinics, and/or 
other community health and social services as appropriate for the 
emission guideline addressed.
---------------------------------------------------------------------------

    \294\ Consistent with this principle of providing reasonable 
notice under the CAA, under programs other than CAA section 111(d), 
the EPA similarly requires states to provide specific notice to an 
area affected by a particular proposed action. See e.g., 40 CFR 
51.161(b)(1) requiring specific notice for an area affected by a 
state or local agency's analysis of the effect on air quality in the 
context of the New Source Review program; 40 CFR 51.102(d)(2), (4), 
and (5) requiring specific notice for an area affected by a CAA 
section 110 SIP submission.
    \295\ FACT SHEET: Biden-Harris Administration Mobilizes 
Resources to Connect Tribal Nations to Reliable, High-Speed internet 
(Dec. 22, 2021). https://www.whitehouse.gov/briefing-room/statements-releases/2021/12/22/fact-sheet-biden-harris-administration-mobilizes-resources-to-connect-tribal-nations-to-reliable-high-speed-internet/; 7% of Americans don't use the 
internet. Who are they? Pew Research Center (Apr. 2, 2021), https://www.pewresearch.org/fact-tank/2021/04/02/7-of-americans-dont-use-the-internet-who-are-they/.
---------------------------------------------------------------------------

    Given the public health and welfare objectives of CAA section 
111(d) in regulating specific existing sources, the EPA believes it is 
reasonable to require meaningful engagement as part of the state plan 
development public participation process in order to further these 
objectives. Additionally, CAA section 301(a)(1) provides that the EPA 
is authorized to prescribe such regulations ``as are necessary to carry 
out [its] functions under [the CAA].'' The proposed meaningful 
engagement requirements would effectuate the EPA's function under CAA 
section 111(d) in prescribing a process under which states submit plans 
to implement the statutory directives of this section. Therefore, the 
EPA is proposing additional meaningful engagement requirements to 
ensure that pertinent stakeholders have reasonable notice of relevant 
information and the opportunity to participate in the state plan 
development throughout the process. The EPA intends to propose similar 
meaningful engagement provisions to this provision under the 
implementing regulations in a separate upcoming rulemaking that would 
apply generally to new EG promulgated under CAA section 111(d). While 
inviting comments on the application of these proposed revisions in the 
context of the oil and gas sector in this rulemaking, the EPA also 
encourages the public to provide comments on these proposed revisions 
more generally in that upcoming rulemaking process to amend the 
implementing regulations. The EPA intends to finalize that rulemaking 
before finalizing this oil and gas rulemaking.
    Consistent with its intended addition to the implementing 
regulations, in this supplemental proposal, the EPA is proposing 
regulatory text for EG OOOOc in 40 CFR 60.5365c regarding the proposed 
meaningful engagement requirements that states must complete prior to 
the submittal of their state plans. In particular, the EPA is proposing 
to define meaningful engagement as ``. . . timely engagement with 
pertinent stakeholder representation in the plan development or plan 
revision process. Such engagement must not be disproportionate nor 
favor certain stakeholders. It must include the development of public 
participation strategies to overcome linguistic, cultural, 
institutional, geographic, and other barriers to participation to 
assure pertinent stakeholder representation, recognizing that diverse 
constituencies may be present within any particular stakeholder 
community. It must include early outreach, sharing information, and 
soliciting input on the State plan.'' The EPA is also proposing to 
define that pertinent stakeholders ``. . .include, but are not limited 
to, industry, small businesses, and communities most affected by and/or 
vulnerable to the impacts of the plan or plan revision.'' Increased 
vulnerability of communities may be attributable, among other reasons, 
to both an accumulation of negative and lack of positive environmental, 
health, economic, or social conditions within these populations or 
communities. Examples of such communities have historically included, 
but are not limited to, communities of color (often referred to as 
``minority'' communities), low-income communities, tribal and 
indigenous populations, and communities in the United States that 
potentially experience disproportionate health or environmental harms 
and risks as a result of greater vulnerability to environmental 
hazards. Tribal communities or communities in neighboring states may 
also be impacted by a state plan and, if so, should be identified as 
pertinent stakeholders. In addition, to the extent a designated 
facility would qualify for a less stringent standard through 
consideration of RULOF as described in section V.B.3.h of this 
preamble, the state, must identify and engage with the communities most 
affected by and vulnerable to the health and environmental impacts from 
the designated facility considered in a state plan for RULOF 
provisions. The EPA expects that the inclusion of the definitions of 
meaningful engagement and pertinent stakeholders in EG OOOOc will 
provide the states specificity around the meaningful engagement 
requirements while allowing for flexibility in the implementation of 
such requirements.
    In the November 2021 proposal, the EPA proposed to include a 
requirement for a demonstration of meaningful engagement as part of the 
completeness evaluation of a state plan submittal. The EPA is proposing 
regulatory text associated to the proposed meaningful engagement 
demonstration states are to include in their plans as part of the 
completeness criteria. The EPA is proposing that a state would be 
required to provide, in their plan submittal, a list of the pertinent 
stakeholders and a summary of engagement conducted and of the 
stakeholder input provided. The EPA would evaluate the states' 
demonstrations regarding meaningful engagement as part of its 
completeness evaluation of a state plan submittal. If a state plan 
submission does not include the required elements for public 
participation, including requirements for meaningful engagement, this 
may be grounds for the EPA to find the submission incomplete or to 
disapprove the plan. The EPA is soliciting comment on the proposed 
definitions of meaningful engagement and pertinent stakeholders as well 
as the inclusion of meaningful engagement requirements in completeness 
criteria for state plan submission. The EPA also solicits comments on 
examples or models of meaningful engagement by states, including best 
practices and challenges.
    During the state plan process, the EPA expects states to identify 
the pertinent stakeholders. As part of efforts to ensure

[[Page 74830]]

meaningful engagement, states will share information and solicit input 
on plan development and on any accompanying assessments. This 
engagement will help ensure that plans achieve the appropriate level of 
emission reductions, that communities most affected by and vulnerable 
to the health and environmental impacts from the designated facilities 
partake in the benefits of the state plan, and that these communities 
are protected from being adversely impacted by the plan. In addition, 
the EPA recognizes that emissions from designated facilities could 
cross state and/or Tribal borders, and therefore may affect communities 
in neighboring states or Tribal lands. The EPA expects that the 
discussion in section VI of the November 2021 proposal (86 FR 63139) 
will assist the states in the identification of pertinent stakeholders. 
The EPA is soliciting comment on how meaningful engagement should apply 
to pertinent stakeholders inside and outside of the borders of the 
state that is developing a state plan, for example, if a state should 
coordinate with the neighboring state and/or tribes for engagement or 
directly contact the affected communities.
    The EPA further proposes to allow a state to request the approval 
of different state procedures for public participation. The EPA 
proposes to require that such alternate state procedures do not 
supersede the meaningful engagement requirements, so that a state would 
still be required to comply with the meaningful engagement requirements 
even if they apply for a different procedure than the other public 
notice and hearing requirements. The EPA is however also proposing that 
states may apply for, and the EPA may approve, alternate meaningful 
engagement procedures if, in the judgement of the Administrator, the 
procedures, although different from the requirements of this subpart, 
in fact provide for adequate notice to and meaningful engagement of the 
public. The EPA is soliciting comment on the distinction between 
request for approval of alternate state procedures to meet public 
notice and hearing requirements from those to meet meaningful 
engagement, and comment on the consideration of request for approval of 
alternate meaningful engagement procedures.
    The EPA conducted meaningful engagement prior to the November 2021 
proposal. The EPA believes this example will provide states with ideas 
for how they can structure their own meaningful engagement activities. 
States are not limited by the EPA's example, but rather the EPA's 
example should be viewed as a minimum of what type of engagement is 
considered sufficient to meet the meaningful engagement requirement for 
purpose of state plan submittal.
    Prior to the November 2021 proposal, the EPA identified stakeholder 
groups likely to be interested in the proposal 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.\296\ Specifically, on May 27, 2021, the EPA 
held a webinar-based training designed for communities affected by this 
rule.\297\ 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. 298 299
---------------------------------------------------------------------------

    \296\ For more information about the EPA's pre-proposal outreach 
activities, please see EPA Docket ID No. EPA-HQ-OAR-2021-0295 and 
EPA-HQ-OAR-2021-0317. For a description of the themes that 
commenters raised please see the 2021 November proposal at 86 FR 
63143.
    \297\ https://www.epa.gov/sites/default/files/2021-05/documents/us_epa_training_webinar_on_oil_and_natural_gas_for_communities.5.27.2021.pdf.
    \298\ June 15, 2021 session: https://youtu.be/T8XwDbf-B8g; June 
16, 2021. session: https://www.youtube.com/watch?v=l23bKPF-5oc; June 
17, 2021 session: https://www.youtube.com/watch?v=R2AZrmfuAXQ.
    \299\ Full transcripts for the listening sessions are posted at 
EPA Docket ID No. EPA-HQ-OAR-2021-0295.
---------------------------------------------------------------------------

    In addition to the trainings and listening sessions, the EPA 
engaged with community leaders potentially impacted by this proposed 
action by hosting a meeting with EJ community leaders on May 14, 2021. 
The EPA provided the public with factual information to help them 
understand the issues addressed by the November 2021 proposal. 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 the 
November 2021 proposal.
    In addition to the engagement conducted prior to the November 2021 
proposal, the EPA provided 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 trainings on the proposed rule and a public 
hearing. EPA hosted three half-day trainings November 16 through 18, 
2021, to provide background information, an overview of the proposed 
rule, stakeholder panel discussions, and information on how to 
effectively engage in the regulatory process. The trainings were open 
to the public, with a focus on communities with EJ concerns, Tribes and 
small business stakeholders. The public hearing occurred on November 30 
to December 2, 2021, and the EPA requested speakers 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.
    The EPA expects that the description of the meaningful engagement 
with pertinent stakeholders included in the preamble and in the docket 
of this rulemaking will serve as a guide of the meaningful engagement 
demonstration states are to include in their plans as part of the 
completeness criteria.

C. Components of State Plan Submission

    While the EPA is not proposing any changes from the November 2021 
proposal to this section, the EPA is proposing to add a provision for 
electronic submission of state plans. The provision at 40 CFR 
60.23a(a)(1) currently requires state plan submissions to be made in 
accordance with the provision in 40 CFR 60.4. Pursuant to 40 CFR 
60.4(a), all requests, reports, applications, submittals, and other 
communications to the Administrator pursuant to 40 CFR part 60 shall be 
submitted in duplicate to the appropriate Regional Office of the EPA. 
The provision in 40 CFR 60.4(a) then proceeds to include a list of the 
corresponding addresses for each Regional Office. In this supplemental 
proposal, the EPA is proposing to require electronic submission of 
state plans instead of paper copies as according to 40 CFR 60.4. In 
particular, the EPA is proposing to include a sentence in 40 CFR 
60.5362c(a) that reads as follows: ``The submission of such plan shall 
be made in electronic format according with 40 CFR 60.5362c(d) of this 
subpart.'' In 40 CFR 60.5362c(d), the EPA is proposing the requirements 
associated with the electronic submittal of plans.

[[Page 74831]]

    As previously described, CAA section 111(d) requires the EPA to 
promulgate a ``procedure'' similar to that of CAA section 110 under 
which states submit plans. The statute does not prescribe a specific 
platform for plan submissions, and the EPA reasonably interprets the 
procedure it must promulgate under the statute as allowing it to 
require electronic submission. Requiring electronic submission is 
reasonable for the following reasons. Providing for electronic 
submittal of CAA section 111(d) state plans in EG OOOOc in place of 
paper submittals aligns with current trends in electronic data 
management and will result in less burden on the states. It is the 
EPA's experience that the electronic submittal of information increases 
the ease and efficiency of data submittal and data accessibility. The 
EPA's experience with the electronic submittal process for SIPs under 
CAA section 110 has been successful as all the states are now using the 
State Planning Electronic Collaboration System (SPeCS). SPeCS is a 
user-friendly, web-based system that enables state air agencies to 
officially submit SIPs and associated information electronically for 
review and approval to meet their CAA obligations related to attaining 
and maintaining the NAAQS. SPeCS is the EPA's preferred method for 
receiving such SIPs submissions. The EPA has worked extensively with 
state air agency representatives and partnered with E-Enterprise for 
the Environment and the Environmental Council of the States to develop 
this integrated electronic submission, review, and tracking system for 
SIPs. SPeCS can be accessed by the states through the CDX. The CDX is 
the Agency's electronic reporting site and performs functions for 
receiving acceptable data in various formats. The CDX registration site 
supports the requirements and procedures set forth under the EPA's 
Cross-Media Electronic Reporting Regulation, 40 CFR part 3.
    The EPA is proposing to include the requirements associated with 
the electronic submittal of a state plan in EG OOOOc. As proposed, EG 
OOOOc will require state plan submission to the EPA be via the use of 
SPeCS or through an analogous electronic reporting tool provided by the 
EPA for the submission of any plan required by this subpart. The EPA is 
also proposing to include language to specify that states are not to 
transmit CBI through SPeCS. Even though state plans submitted to the 
EPA for review and approval pursuant to CAA section 111(d) through 
SPeCS are not to contain CBI, this language will also address the 
submittal of CBI in the event there is a need for such information to 
be submitted to the EPA. The requirements for electronic submission of 
CAA section 111(d) state plans in EG OOOOc will ensure that these 
Federal records are created, retained, and maintained in electronic 
format. Electronic submittal will also improve the Agency's efficiency 
and effectiveness in the receipt and review of state plans. The 
electronic submittal of state plans may also provide continuity in the 
event of a disaster like the one our nation experienced with COVID-19. 
The EPA requests comment on whether the EPA should provide for 
electronic submittals of plans as an option instead of as a 
requirement. The EPA requests comment on whether a requirement for 
electronic submissions of CAA section 111(d) state plans should be via 
SPeCS or whether another electronic mechanism should be considered as 
appropriate for CAA section 111(d) state plan submittals.

D. Timing of State Plan Submissions and Compliance Times

    Background and Court Decision Re: Vacated Timelines. Under CAA 
section 111(d), it is first the EPA's responsibility to establish a 
BSER and a presumptive level of stringency via a promulgated EG. It is 
then each state's obligation to submit a plan to the EPA that 
establishes standards of performance for each designated facility. The 
EPA acknowledged in the November 2021 proposal that the D.C. Circuit 
vacated certain timing provisions within 40 CFR part 60, subpart Ba. 
Am. Lung Assoc. v. EPA, 985 F.3d at 991 (D.C. Cir. 2021) (ALA). See 86 
FR 63255 (November 15, 2021). These vacated timing requirements 
include: the timeline for state plan submissions, the timeline for the 
EPA to act on a state plan, the timeline for the EPA to promulgate a 
Federal plan, and the timeline that dictates when state plans must 
include increments of progress. As a result of the court's vacatur, no 
regulations currently govern the timing of these actions for EGs 
promulgated after July 8, 2019.\300\ The Agency plans to undertake a 
separate rulemaking to address these vacated provisions in subpart Ba 
for purposes of the implementing regulations, including a generally 
applicable deadline for state plan submissions. However, the EPA 
solicited comment in the November 2021 proposal on any facts and 
circumstances that are unique to the oil and natural gas industry that 
the EPA should consider when proposing a timeline for plan submission 
applicable to a final EG for this source category. The EPA is now 
proposing to require that each state adopt and submit to the 
Administrator, within 18 months after publication of the final EG 
OOOOc, a plan for the control of GHGs in the form of limitations on 
methane to which EG OOOOc applies. As described further in this 
section, an 18-month deadline for state plans addressing EG OOOOc both 
appropriately accommodates the process required by states to develop 
plans to effectuate the EG OOOOc, and is consistent with the objective 
of CAA section 111(d) to ensure that designated facilities control 
emissions of GHGs that the EPA has determined may be reasonably 
anticipated to endanger public health or welfare.
---------------------------------------------------------------------------

    \300\ The court did not vacate the applicability provision for 
subpart Ba under 40 CFR 60.20a(a).
---------------------------------------------------------------------------

    The EPA notes that the portions of the implementing regulations 
under subpart Ba that were not affected by the court's vacatur, the 
November 2021 proposal, and this supplemental proposal collectively lay 
out all of the required components of, and requirements for, state 
plans for purposes of EG OOOOc. Therefore, states will have the 
necessary information at that time to develop state plans to meet the 
requirements of any final EG OOOOc. Any separate rulemaking to address 
the vacated provisions in subpart Ba will not add to or change these 
required components. The EPA intends to propose deadlines for its 
action on state plan submissions and for promulgation of a Federal plan 
in its separate rulemaking. These deadlines are intended to apply 
generally to these actions implementing EGs under CAA section 111(d), 
including to the EPA's action on state plan submissions and 
promulgation of a Federal plan under the final EG OOOOc. It is not 
necessary for the EPA to propose deadlines on its own action on state 
plans submitted in response to a final EG OOOOc, or promulgation of a 
Federal plan where a state fails to submit an approvable plan, as part 
of this supplemental proposal because these deadlines are not relevant 
to states in the development of their plans, and go to the EPA's 
actions subsequent to the states' development of their plans. However, 
the EPA intends to propose and finalize these deadlines not later than 
finalization of an EG OOOOc, so that states and stakeholders will have 
knowledge of them as development on state plans begins. Additionally, 
as described further in this section, the EPA is proposing the final 
compliance schedule for designated facilities to run from the deadline 
for state plan submissions. Accordingly, the compliance deadline for 
any final EG

[[Page 74832]]

OOOOc will also be knowable and provide certainty of obligations to 
regulated entities and other stakeholders in advance of state plan 
development. The D.C. Circuit's vacatur of the extended timelines in 
subpart Ba was based both on the EPA's failure to substantiate the 
necessity for the additional time at each step of the administrative 
process, and the EPA's failure to address how those extended 
implementation timelines would impact public health and welfare. 
Accordingly, for EG OOOOc, the EPA has evaluated these factors and is 
proposing the 18-month state plan deadline based on the minimum 
administrative time reasonably necessary for each step in the 
implementation process thus, minimizing impacts on public health and 
welfare. This approach addresses both aspects of the ALA decision 
because states will take no longer than necessary to develop and adopt 
plans that impose requirements consistent with the overall objectives 
of CAA section 111(d).
    The EPA acknowledges this proposed 18-month deadline is not 
identical to the generally applicable three year-deadline for SIPs 
under CAA section 110, which the agency adopted in the vacated subpart 
Ba rule. However, the EPA's proposed deadline is consistent with the 
requirement of CAA section 111(d) that the EPA to promulgate a 
procedure ``similar'' to that of CAA section 110, rather than an 
identical procedure. This is also consistent with the ALA decision, 
which requires the EPA to ``engage meaningfully with the different 
scale'' of CAA section 111(d) and 110 plans. Am. Lung Ass'n v. EPA, 985 
F.3d 914, 993 (D.C. Cir. 2021). Accordingly, the EPA evaluated each 
step of the OOOOc implementation process to independently determine the 
appropriate duration of time to accomplish the given step as part of 
the overall process, and the proposed timeline represents what the EPA 
is proposing to determine will be necessary for a state plan upon 
publication of any final EG OOOOc.
    As described previously, no timing requirements for state plan 
submissions are currently in effect for EGs published after July 8, 
2019. The original implementing regulations promulgated under subpart B 
in 1975, which are applicable to EGs published before July 8, 2019, 
provide that states have nine months to submit a state plan after 
publication of a final EG. 40 CFR 60.23(a)(1). In 2019, the EPA 
promulgated subpart Ba and provided three years for states to submit 
plans, consistent with the timelines provided for submission of SIPs 
pursuant to CAA section 110(a)(1). This 3-year timeframe was vacated in 
the ALA decision, and thus currently there is no applicable deadline 
for state plan submissions required under EGs subject to subpart Ba. In 
evaluating the appropriate timeline for plan submittal to propose for 
EG OOOOc, the EPA reviewed steps that states need to carry out to 
develop, adopt, and submit a state plan to the EPA, and its history in 
implementing EGs under the timing provisions of subpart B. The EPA 
further evaluated statutory deadlines, contents, and processes for 
relatively comparable state plans under CAA sections 129 and 182. The 
EPA also considered the characteristics of the Crude Oil and Natural 
Gas source category to assist justification for the timelines and 
address how the timeline will impact health and welfare.
    In developing a CAA section 111(d) state plan, a state must 
consider multiple components in meeting applicable requirements. In 
addition to any requirements that an EG specifies for state plans, 
subpart Ba specifies certain fundamental elements that must be included 
in a state plan submission (see 40 CFR 60.24a, 60.25a, 60.26a) and 
certain processes that a state plan must undergo in adopting and 
submitting a plan (see 40 CFR 60.23a). In addition to these EPA 
requirements for state plans, there are also state-specific processes 
applicable to the development and adoption of a state plan. In 
particular, the component that the EPA expects to take the most time 
and have the most variability from state to state is the administrative 
process (e.g., through legislative processes, regulation, or permits) 
that establishes standards of performance. Considering this 
variability, 18 months should adequately accommodate the differences in 
state processes necessary for the development of a state plan that 
meets applicable requirements. The EPA evaluated data from previously 
implemented EGs, and the statutory deadlines and data from analogous 
programs (i.e., CAA section 129), as described below, to help inform 
this proposed 18-month timeline.
    Subpart B provides nine months for states to submit plans after 
publication of a final EG. The EPA's review of state's timeliness for 
submitting CAA section 111(d) plans under the 9-month timeline 
indicates that most states either did not submit plans or submitted 
plans that were substantially late. We note that the plans submitted 
under subpart B were not subject to the additional requirements the EPA 
is proposing for meaningful engagement and consideration of RULOF, 
respectively described in section V.B. Based on the lack of timeliness 
of prior state plan submissions under subpart B and the additional 
requirements of this proposal, EG OOOOc, nine months is not a suitable 
amount of time for most states to adequately develop a plan for an EG.
    To help inform what is an appropriate proposal for the state plan 
submission deadline, the EPA also reviewed CAA section 129's statutory 
deadline and requirements for state plans, and the timeliness and 
responsiveness of states under CAA section 129 EGs. CAA section 129 
references CAA section 111(d) in many instances, creating considerable 
overlap in the functionality of the programs. Notably, existing solid 
waste incineration units are subject to the requirements of both CAA 
sections 129 and 111(d). CAA section 129(b)(1). The processes for CAA 
sections 111(d) and 129 are very similar in that states are required to 
submit plans to implement and enforce the EPA's EGs. However, there are 
some key distinctions between the two programs, most notably that CAA 
section 129(b)(2) specifies that state plans be submitted no later than 
1 year from the promulgation of a corresponding EG, whereas the statute 
does not specify a particular timeline for state plan submissions under 
CAA section 111(d) and is instead governed by the EPA's implementing 
regulations (i.e., subparts B and Ba). Moreover, CAA section 129 plans 
are required by statute to be at least as protective as the EPA's EGs. 
However, CAA section 111(d) permits states to take into account 
remaining useful life and other factors, which suggests that the 
development of a CAA section 111(d) plan could involve more complicated 
analyses than a CAA section 129 plan (see section V.B. for more 
information on RULOF provisions). The contrast between the CAA section 
129 plans and CAA section 111(d) plans suggests that in determining the 
timeframe for CAA section 111(d) plan submissions the EPA should 
provide for a longer timeframe than the 1 year timeframe the statute 
provides under CAA section 129.
    The EPA found that a considerable number of states have not made 
required state plan submissions in response to a CAA section 129 EG. In 
instances where states submitted CAA section 129 plans, a significant 
number of states submitted plans between 14 to 17 months after the 
promulgated EG. This suggests that states will typically need more than 
1 year to develop a state plan to implement an EG, particularly for a 
program that permits more source-

[[Page 74833]]

specific analysis than under CAA section 129 as CAA section 111(d) 
does.
    In the 2019 promulgation of subpart Ba, the EPA mirrored CAA 
section 110 by giving states 3 years to submit plans. As previously 
described, the court partly faulted the EPA for adopting the CAA 
section 110 timelines without accounting for the differences in scale 
and scope between CAA section 110 and 111(d) plans. The EPA has now 
more closely evaluated the statutory deadlines and requirements in the 
CAA section 110 implementation context to determine what might be 
feasible for an OOOOc EG state plan submission timeline. The EPA 
specifically focused on statutory SIP submission deadline and 
requirements in the context of attainment plans for the ozone NAAQS. 
Subpart 2 of Title I of the CAA contains a number of deadlines for 
ozone attainment plans that are 2 years or longer. For example, areas 
initially designated Marginal have two years from designation to submit 
a SIP that contains a permitting program and emissions inventory. CAA 
section 182(a). Areas initially designated Moderate have two years to 
submit a plan implementing reasonable available control technologies 
under CAA section 182(b)(2)), and three years to submit their 
attainment plan and other requirements under CAA section 182(b)(1). 
These ozone attainment plans are arguably more complicated for states 
to develop when compared to plans under CAA section 111(d) for EG 
OOOOc. For example, ozone attainment plans require states to determine 
how to control a variety of sources, based on extensive modeling and 
analyses, in order to bring a nonattainment area into attainment of the 
NAAQS by a specified attainment date. Under CAA section 111(d) and EG 
OOOOc, it is clear which designated facilities must be subject to a 
state plan, and the standards of performance for these sources must 
generally reflect the level of stringency determined by the EG unless a 
state chooses to account for RULOF. Additionally, ozone attainment 
plans must contain inventories of actual emissions from certain 
sources, whereas the EPA is proposing to supersede the subpart Ba 
inventory requirement for purposes of this EG. The difference in 
complexity between the CAA ozone attainment plan requirements and the 
plan requirements for EG OOOOc suggests that a timeline of 18 months is 
more appropriate for developing state plans submissions in response to 
this EG.
    Furthermore, the EPA considered the characteristics of the Crude 
Oil and Natural Gas source category. The EPA believes that EG OOOOc has 
the potential to require states to perform considerable engineering 
and/or economic analyses for their plan. For example, the EPA 
anticipates considerable engineering analyses for when states chose to 
leverage their existing state programs and determine that their 
existing state program meets the criteria to conduct a source-by-source 
stringency comparison. The engineering analysis can become more complex 
should a state chooses to utilize a different design, equipment, work 
practice, and/or operational standard than the EG because a qualitative 
assessment will have a number of metrics that require evaluation. The 
EPA also anticipates states will need to conduct considerable 
engineering and economic analysis should a state invoke RULOF. As 
discussed in section V.C., when invoking RULOF, the plan submission 
must identify all control technologies available for the source and 
evaluate the BSER factors for each technology, using the same metrics 
and evaluating them in the same manner as the EPA did in developing the 
EG. For example, if the EPA considered capital cost as part of the BSER 
analysis, the state will also need to consider the same.
    The EPA has long recognized the unique nature of the Crude Oil and 
Natural Gas source category because, in comparison to other EG, it is 
geographically spread out covering multiple industry segments. 
Specifically, the EPA defines the Crude Oil and Natural Gas source 
category to mean: (1) Crude oil production, which includes the well and 
extends to the point of custody transfer to the crude oil transmission 
pipeline or any other forms of transportation; and (2) natural gas 
production, processing, transmission, and storage, which include the 
well and extend to, but do not include, the local distribution company 
custody transfer station.\301\ The Crude Oil and Natural Gas source 
category impacts a great number of states, tribes, and U.S. territories 
in some capacity. U.S. Energy Information Administration (EIA) 
production data shows thirty-four states that have crude oil and or 
natural gas production.\302\ Except for Vermont and Hawaii, the states 
not producing crude oil and or natural gas have compressor stations in 
the transmission and storage segment. The EPA understands that EG OOOOc 
for the Crude Oil and Natural Gas source category will apply to an 
extraordinary number of designated facilities and for many designated 
facilities the standards are complex compared to other EG. For example, 
in the U.S., the EPA has identified over 15,000 oil and gas owners and 
operators, around 1 million producing onshore oil and gas wells, about 
5,000 gathering and boosting facilities, over 650 natural gas 
processing facilities, and about 1,400 transmission compression 
facilities. States will need to develop and draft plans covering these 
designated facilities that include the required components, such as 
standards of performance and implementation measures for such 
standards, and adopt the plans through their required administrative 
processes before submitting them to the EPA. EG OOOOc covers numerous 
designated facilities with corresponding presumptive standards. By 
comparison, the EPA's EG for Municipal Solid Waste Landfills included 
one designated facility type, affecting approximately 1,000 landfills. 
81 FR 59313 (August 29, 2016). Of these 1,000 landfills, approximately 
731 will be affected by the collection and control standard laid out in 
the rule, approximately 93 more landfills than the 1996 Municipal Solid 
Waste Landfills EG. 61 FR 9919 (March 12, 1996).
---------------------------------------------------------------------------

    \301\ For purposes of the November 2021 proposal and this 
supplemental 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''.
    \302\ See https://www.eia.gov/dnav/pet/pet_crd_crpdn_adc_mbblpd_a.htm and https://www.eia.gov/dnav/ng/ng_prod_sum_a_EPG0_FGW_mmcf_a.htm.
---------------------------------------------------------------------------

    The EPA also recognizes the need to address potential health and 
welfare impacts of methane emissions from this source category. The EPA 
discusses extensively in section III of the November 2021 proposal 
\303\ titled, ``Air Emissions from the Crude Oil and Natural Gas Sector 
and Public Health and Welfare,'' and in section VI of the November 2021 
proposal titled, ``Environmental Justice Considerations, Implications, 
and Stakeholder Outreach,'' the urgent need to mitigate climate-
destabilizing pollution and protecting human health by reducing GHG 
emissions from the Oil and Natural Gas Industry,\304\ specifically, the 
Crude Oil and Natural Gas source category.\305\

[[Page 74834]]

The Oil and Natural Gas Industry is the United States' largest 
industrial emitter of methane, a highly potent GHG. Human activity-
related emissions of methane are responsible for about one third of the 
warming due to well-mixed GHGs and constitute the second most important 
warming agent arising from human activity after carbon dioxide (a well-
mixed gas is one with an atmospheric lifetime longer than a year or 
two, which allows the gas to be mixed around the world, meaning that 
the location of emission of the gas has little importance in terms of 
its impacts). According to the Intergovernmental Panel on Climate 
Change (IPCC), strong, rapid, and sustained methane reductions are 
critical to reducing near-term disruption of the climate system and are 
a vital complement to reductions in other GHGs that are needed to limit 
the long-term extent of climate change and its destructive impacts. The 
need to balance the complexity of EG OOOOc and the need to mitigate 
climate change and protecting human health further suggest that a 
timeline of 18 months is more appropriate for development of state 
plans submissions.
---------------------------------------------------------------------------

    \303\ See 86 FR 63110 (November 15, 2021).
    \304\ 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.
    \305\ The EPA defines the Crude Oil and Natural Gas source 
category to mean: (1) Crude oil production, which includes the well 
and extends to the point of custody transfer to the crude oil 
transmission pipeline or any other forms of transportation; and (2) 
natural gas production, processing, transmission, and storage, which 
include the well and extend to, but do not include, the local 
distribution company custody transfer station. For purposes of this 
proposed rulemaking, for crude oil, the EPA's focus is on operations 
from the well to the point of custody transfer at a petroleum 
refinery, while for natural gas, the focus is on all operations from 
the well to the local distribution company custody transfer station 
commonly referred to as the ``city-gate''.
---------------------------------------------------------------------------

    Thus, based on the EPA's evaluation of states' responsiveness to 
previous CAA section 111(d) EGs, the contrast between the development 
of CAA section 111(d) plans and CAA section 129 plans, the complexity 
of the source category and designated facilities, and the need to 
quickly take action to address critical climate and health and welfare 
impacts, the EPA is proposing to require that state plans under EG 
OOOOc be due 18 months after publication of the final EG. This proposed 
timeframe is substantially shorter than the 3-year deadline vacated by 
the D.C. Circuit; however, it should give states adequate time to adopt 
and submit approvable plans without extending the timing such that 
significant adverse impacts to health and welfare are likely to occur 
from the foregone emission reductions during the state planning 
process. Allowing states sufficient time to develop feasible 
implementation plans for their designated facilities that adequately 
address public health and environmental objectives will ultimately help 
ensure timelier implementation of EG OOOOc, and therefore achievement 
in actual emission reductions, than would an unattainable deadline that 
may result in the failure of states to submit plans and require the 
development and implementation of a Federal plan.
    The EPA recognizes that the court, in ALA, faulted the Agency for 
failing to consider the potential impacts to public health and welfare 
associated with extending planning deadlines. The EPA does not 
interpret the court's direction to require a quantitative measure of 
impact, but rather consideration of the importance of the public health 
and welfare goals when determining appropriate deadlines for 
implementation of regulations under CAA section 111(d). Because 18 
months is the minimum period of time in which the EPA finds that most 
states can expeditiously create and submit a plan that meets applicable 
requirements for EG OOOOc, it follows that the EPA has appropriately 
considered the potential impacts to public health and welfare 
associated with this extension of time by providing no more time than 
the states reasonably need to ensure a plan is comprehensive and 
timely. The EPA is soliciting comment on the proposed 18-month state 
plan submission deadline upon publication of the final EG OOOOc, and 
the analysis supporting the EPA's proposed determination regarding the 
amount of time reasonably necessary for plan development and 
submission. The EPA is also soliciting comment on whether the EPA 
should consider any other factors in setting this deadline.
    As discussed in section V.B of this preamble, the EPA is proposing 
to include a requirement for states to undertake outreach and 
meaningful engagement with pertinent stakeholders as part of the state 
plan development process. The EPA solicits comment on how much, if any, 
time this additional engagement will take in the state plan development 
process.
    In section V.B of this preamble, the EPA is also proposing 
revisions to the RULOF provision. These proposed revisions would 
clarify the procedures for considering RULOF by establishing a robust 
analytical framework that would require a state to provide a sufficient 
justification when applying a standard of performance that is less 
stringent than the EPA's presumptive level of stringency, thereby 
allowing the EPA to readily determine if the state's plan is 
satisfactory and therefore approvable. The proposed state plan 
submission timeline of 18 months should adequately provide time for 
states to conduct the analyses required by this provision; however, the 
EPA is soliciting comment on whether states will need additional time 
in the plan development to account for instances where RULOF is 
considered. The EPA is specifically requesting comment on how much 
additional time might be required for this consideration and how that 
additional time fits within the entire process of state plan 
development.
    The proposed state plan submission timeline should be generally 
achievable by states. The EPA notes it is obligated to promulgate a 
Federal plan for states that have not submitted a plan by the 
submission deadline. Once the obligation to promulgate a Federal plan 
is triggered, it can only be tolled by the EPA's approval of a state 
plan. If a Federal plan is promulgated, a state may still submit a plan 
to replace the Federal plan. A Federal plan under CAA section 111(d) is 
a means to ensure timely implementation of EGs, and a state may choose 
to accept a Federal plan for their sources rather than submit a state 
plan. While the EPA encourages states to timely submit plans, there are 
no mandatory sanctions associated with submitting a late plan or 
accepting the implementation of a Federal plan.
    Timeline for State Plan Compliance Schedule. Under 40 CFR 
60.22a(b)(5), the EPA in an EG is required to provide, among other 
things, ``the time within which compliance with standards of 
performance can be achieved''. Each state plan must then 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 
its 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.'' 341 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 November 2021 proposal proposed requiring that state plans 
impose a compliance timeline on

[[Page 74835]]

designated facilities to require final compliance with the standards of 
performance as expeditiously as practicable, but no later than 2 years 
following the state plan submittal deadline. 86 FR 63256 (November 15, 
2021). Commenters on the proposal indicated that more than 2 years 
after the submittal of a state plan was needed to come into compliance 
for existing sources. Given the number of designated facilities that 
would need to come into compliance, commenters explained that requiring 
existing sources to upgrade at the same time would place a substantial 
burden on the supply chain (all orders at the same time) and vendors 
(all install at the same time). Commenters stated that, if compliance 
timelines are too short, there will be significant economic disruptions 
for both the companies operating these facilities as well as the 
manufacturers who support them. Commenters also stated that there would 
be a need to train a tremendous number of staff on the regulatory 
requirements and actions needed to comply. A few of the commenters 
representing states also noted that 2 years from state plan submittal 
would not allow sufficient time for states to issue the air quality 
permits in advance of the compliance date for the sources to have 
regulatory requirements with which to demonstrate compliance. 
Environmental commenters supported the EPA's proposed requirement that 
state plans include a compliance timeline within no more than 2 years 
of plan submission and urged the Agency to consider whether a more 
abbreviated compliance timeline is warranted.\306\
---------------------------------------------------------------------------

    \306\ See Document ID No. EPA-HQ-OAR-2021-0317-0844.
---------------------------------------------------------------------------

    In evaluating whether to revise the November 2021 proposed two-year 
final compliance deadline, the EPA considered several factors that 
could impact the ability of a designated facility to come into 
compliance with the proposed presumptive standards. These factors are 
presented in Table 38.

    TABLE 38--Factors Considered When Determining Compliance Timeline
------------------------------------------------------------------------
                 Factor                            Description
------------------------------------------------------------------------
Design/Purchase Equipment..............  Equipment must be purchased and
                                          installed to comply. This
                                          could be control equipment or
                                          specific equipment to meet an
                                          equipment standard (e.g.,
                                          solar powered pneumatic
                                          controller). This would also
                                          typically involve design
                                          considerations.
Availability of Equipment (Supply Chain  This factor is related to the
 Issues).                                 potential shortage of
                                          available equipment. Note that
                                          this could have an impact on
                                          small businesses as the
                                          assumption is that larger
                                          businesses would be supplied
                                          first.
Cost of Equipment (Individual            The cost of equipment for an
 Designated Facility).                    individual designated
                                          facility. This cost may
                                          disproportionally impact small
                                          businesses.
Performance Testing....................  The requirement for a
                                          performance testing requires
                                          securing the services of a
                                          testing contractor, scheduling
                                          and planning the test, and
                                          notifying/coordinating with
                                          the state agency. In addition
                                          to control device performance
                                          testing, this would also
                                          include monitoring (e.g.,
                                          fugitive component
                                          monitoring).
Complexity of Requirements.............  More complex requirements may
                                          need more time for owners and
                                          operators to understand the
                                          requirements and develop
                                          procedures upfront to ensure
                                          initial and continuing
                                          compliance.
Availability of Specialized Services     This is related to the
 (Monitoring).                            potential shortage of
                                          available specialized services
                                          (e.g., OGI contractors). Note
                                          that this could have an impact
                                          on small businesses as the
                                          assumption is that contractors
                                          could prioritize larger
                                          businesses.
Number of Designated Facilities........  The sheer number of designated
                                          facilities may have an impact
                                          on the ability to comply
                                          within a specified timeline,
                                          which assumes that it will
                                          potentially be more
                                          problematic for companies
                                          owning many designated
                                          facilities to comply in a
                                          shorter time frame.
Existing Sources Covered by State        If the designated facility is
 Regulation.                              covered by state regulations
                                          that cover existing sources to
                                          a degree equivalent to the EG,
                                          the number of designated
                                          facilities needing to comply
                                          with be less.
Emissions Reduced/Total Designated       The overall methane emissions
 Facility.                                reduction that will result
                                          from control of existing
                                          sources under the EG. EPA
                                          could prioritize designated
                                          facilities to achieve emission
                                          reductions sooner.
------------------------------------------------------------------------

    Some of the factors presented in Table 38 would impact the ability 
of an owner or operator of a designated facility to comply within two 
years more than others. For example, factors that are beyond an owner 
or operator's control, such as the availability of specialized services 
and availability of equipment, can be compounded by the fact that there 
are a large number of designated facilities where owners or operators 
are dependent on the availability of equipment and services. Other 
factors, such as the cost of equipment necessary for a designated 
facility to come into compliance, will impact some owners and operators 
more than others. Small businesses have often reported that large 
businesses generally have an advantage over small businesses in such 
cases. Presumptive standards that include a higher reliance on factors 
that would impact the ability of a designated facility to come into 
compliance, such as those proposed for pneumatic controllers, were 
considered to require more time (i.e., greater than the November 2021 
proposed 2-year time frame). For example, to meet the proposed 
presumptive standards for pneumatic controllers, it is expected that 
more time may be needed due to the anticipated high demand for 
specialized equipment to meet the proposed EG standards and the 
increased reliance on ``design/purchase equipment'', ``availability of 
equipment'', ``cost of equipment,'' and ``number of designated 
facilities.'' Other

[[Page 74836]]

designated facility presumptive standards that are less dependent on 
the need for specialized equipment or services (e.g., fugitive 
emissions work practice standards) might require less time to come into 
compliance than pneumatic controllers but would still require 
considerable upfront planning based on the number of designated 
facilities.
    After consideration of comments received on the November 2021 
proposal and consideration of the factors that could impact the ability 
of a designated facility to come into compliance with the proposed 
presumptive standards, 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 36 months following the state plan 
submittal deadline. The EPA considered requiring differing compliance 
timelines for the differing designated facilities depending on the 
requirements of the proposed presumptive standards and the factors 
presented in Table 38 but chose to include a uniform compliance 
timeframe for all of the designated facilities. The EPA believes that 
establishing a uniform compliance timeline of no later than 36 months 
following the state plan submittal deadline simplifies compliance and 
eases the burden on large and small business owners and operators that 
need to develop and implement plans to meet their compliance 
obligations for a large number of designated facilities. The required 
state plan compliance elements for owners and operators to come into 
compliance include the need to: (1) Become familiar with state plan 
requirements for the nine different types of designated facilities, (2) 
assess all existing sites and operations owned by the company to 
determine the universe of designated facilities that are subject to 
requirements, (3) prepare an increment of progress final control 
compliance plan for meeting standards of performance for all of the 
hundreds, potentially thousands, of designated facilities owned by the 
company, (4) implement a compliance plan for each designated facility, 
(5) ensure standards of performance for designated facility are met by 
required compliance dates, and (6) plan and implement initial 
compliance performance testing, monitoring, recordkeeping, and 
reporting. Each of the nine types of designated facilities include 
various compliance element needs (e.g., engineering assessments, 
requirements to purchase equipment, contract services for modifying 
existing equipment to include add-on control equipment, contract 
services to perform monitoring and/or performance testing, contract 
services to perform maintenance and repair services to ensure 
compliance).
    The level of planning and implementation of a plan to come into 
compliance will differ by each type of designated facility. Further, 
site-specific conditions may require different compliance paths even 
for the same type of designated facility. Another factor to consider is 
the ability of an owner or operator to meet the initial capital and 
labor expenditures needed to develop and implement a compliance plan 
will vary based on the numbers of each of the designated facilities and 
available capital and in-house expertise/labor. Small businesses often 
need more time to absorb the associated capital and labor expenditure 
needs to develop and implement compliance plans. By allowing a uniform 
compliance deadline of 36 months from the time of submittal of the 
state plan to come into compliance, owners and operators are able to 
take into consideration all of the differing designated facilities, 
sites and expenditures that will be needed to comply when they develop 
their compliance plans. This will also reduce any potential confusion 
that could occur with varied compliance deadlines for designated 
facilities that are covered under the proposed EG.
    As previously described, EPA is proposing to require that states 
submit their state plan within 18 months of publication of the EGs. 
Accordingly, linking a 36-month compliance deadline to the state plan 
submittal deadline for purposes of this EG would give sources ample 
time to plan for compliance with an approved state plan. The EPA also 
notes that publication of a final EG will also give sources meaningful 
information as to their potential compliance obligations, such as the 
presumptive standards, in advance of the state plan submittal deadline. 
Though EPA has not yet proposed a timeline for its action on state 
plans in response to the ALA vacatur, and intends to do so in an 
upcoming rulemaking, such timeline cannot be so lengthy as to 
contravene the court's direction to consider potential health and 
welfare impacts of an extended deadline. The EPA believes that a 
compliance deadline 36 months from the state plan submittal deadline 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 and accounts for retrofit 
considerations and potential supply chain issues that owners and 
operators may encounter. The EPA considered whether to link the 
compliance deadline to its approval of a state plan, however, requiring 
compliance with state plans based on the state plan submittal deadline 
rather than the state plan approval date standardizes when designated 
facilities must come into compliance across states.
    Subpart Ba requires that standards of performance are implemented 
in a timely manner through provisions that require legally enforceable 
increments of progress if the compliance schedule extends beyond 24 
months after the state plan submission deadline.\307\ However, the 24-
month timeline for triggering increments of progress was vacated by the 
D.C. Circuit in the ALA decision. Petitioners did not challenge, and 
the court did not vacate, the substantive requirement for increments of 
progress. The EPA intends to address the vacated timeline for 
increments of progress for purposes of the implementing regulations in 
an upcoming rulemaking. For EG OOOOc, because the EPA is proposing a 
final compliance deadline of 36 months after publication of the EG, the 
EPA is proposing to require that state plans must include legally 
enforceable increments of progress in order to better assure compliance 
by each designated facility or category of facilities. While the EPA is 
proposing 36 months after the state plan submission deadline for final 
compliance based on the considerations described above, increments of 
progress will help assure that designated facilities are on track to 
actually achieve compliance by undertaking certain concrete interim 
steps. Taking into consideration the large numbers of designated 
facilities that regulated entities would need to evaluate and plan for 
to come into compliance, we are proposing that state plans require 
owners and operators of designated facilities address two of the five 
incremental of progress steps identified in the definition of 
increments of progress subpart Ba: (1) A final control plan and (2) 
final compliance. The EPA is proposing that the final control plan 
include a compliance plan for each designated facility, but a company 
would be allowed to submit one plan that covers all of the company's 
designated facilities in the state in lieu of submitting a plan for 
each designated facility. The final control plan would be

[[Page 74837]]

required to include an identification of their designated facilities 
and how they are planning to comply with the EGs for each of their 
designated facilities (e.g., air pollution control devices/measures to 
be used to comply with the emission limits, standards and other 
requirements). The final control plan would also be required to include 
all instances where a designated facility is complying with an 
alternative standard (e.g., routing centrifugal compressor wet seal 
emissions to a control device to achieve a 95 percent reduction in 
methane instead of complying with the 3 scfm volumetric flow rate 
standard) or when the owner or operator is planning to claim technical 
infeasibility to allow compliance with an alternative standard (e.g., a 
pneumatic pump that demonstrates it is technically infeasible to use a 
pump that is not driven by natural gas and that is technically 
infeasible to route to control). We are proposing that the final 
control plan be required to be submitted within two years after the 
deadline for the state plan submittals. This timeline allows sufficient 
time for regulated entities to develop their compliance plan for each 
of their designated facilities to meet their compliance obligations. 
The EPA solicits comment on the timing and requirements of this final 
control plan proposal.
---------------------------------------------------------------------------

    \307\ 40 CFR 60.24a(a) and 60.24a(d).
---------------------------------------------------------------------------

    In addition to the final control plan, we evaluated whether to 
require a report that demonstrates final compliance as an increment of 
progress report. We are proposing that state plans include a 
requirement for owners and operators of designated facilities to submit 
a notification of final compliance report for each designated facility 
on or before 60 days after the compliance date of the state plan. Under 
this proposal, a company would be allowed to submit one notification 
that covers all of the company's designated facilities in a state in 
lieu of submitting a notification for each designated facility. As an 
alternative, we evaluated not including a specific requirement for a 
notification of final compliance report. Without a requirement for a 
notification of final compliance report, confirmation that designated 
facilities are complying with a state plan would not occur until the 
first annual report. The EPA determined that requiring a notification 
of final compliance report that was submitted before the first annual 
report was more closely aligned with the intent of a final compliance 
increment of progress step. The EPA solicits comment on this proposed 
notification of final compliance report.

VI. Use of Optical Gas Imaging in Leak Detection (Appendix K)

A. Overview of the November 2021 Proposal

    In the November 2021 proposal, the EPA proposed a protocol for the 
use of OGI in the determination of leaks as Appendix K. The protocol 
was proposed for use in the oil and gas sector but was proposed to have 
broader applicability to surveys of process equipment using OGI cameras 
throughout the entire oil and gas upstream and downstream sectors from 
production through refining to distribution where a subpart in those 
sectors references its use.
    The proposed appendix K was based on extensive literature review on 
the technology development, as well as observations on current 
applications of OGI technology, multiple empirical laboratory studies 
and OGI technology evaluations commissioned by the EPA, and a virtual 
stakeholder workshop hosted by the EPA to gather input on development 
of a protocol for the use of OGI. The proposed appendix K outlined the 
procedures that camera operators would be required to follow to 
identify leaks or fugitive emissions using a field portable infrared 
camera. Additionally, the proposed appendix K contained specifications 
relating to the required performance of OGI cameras, required operator 
training and verification, determination of an operating window for 
performing surveys, and requirements for a monitoring plan and 
recordkeeping.

B. Significant Changes Since Proposal

1. Scope
    The EPA proposed that appendix K would have broad applicability 
across the oil and gas upstream and downstream sectors, but that it 
must be referenced by an applicable subpart before it would apply. This 
would potentially include well sites, compressor stations, boosting 
stations, petroleum refineries, gas processing plants, and gasoline 
distribution facilities. Chemical plants and other facilities outside 
of the oil and gas upstream and downstream sectors were specifically 
excluded in the applicability section.
    Commenters stated that appendix K applicability should not be 
restricted to the oil and gas upstream and downstream sectors.\308\ 
While the EPA originally excluded the chemical sector because there are 
issues with seeing some of the compounds that could be released as 
emissions in some of the chemical sector sources, there are some 
chemical sector sources where most of the emissions are made up of 
compounds that can be imagined by an OGI camera. As such, the EPA is 
proposing to revise the scope and applicability for appendix K to 
remove the sector applicability and to base the applicability on being 
able to image most of the compounds in the gaseous emissions from the 
process equipment. The EPA is retaining the requirement that appendix K 
does not on its own apply to anyone but must be referenced by a subpart 
before it would apply.
---------------------------------------------------------------------------

    \308\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0604, EPA-HQ-
OAR-2021-0317-0748, EPA-HQ-OAR-2021-0317-0808, and EPA-HQ-OAR-2021-
0317-0831.
---------------------------------------------------------------------------

2. Operator Training
    The EPA proposed a multi-layered training requirement for OGI 
camera operators because operator training is critical in developing 
the ability to see leaks with an OGI camera. The proposed training 
consisted of both an initial and annual classroom training on the 
fundamental concepts of OGI, basic operation of the camera, best 
practices for finding leaks, and the site's monitoring plan. appendix K 
also contained initial field training consisting of 100 site surveys 
with a senior OGI camera operator, where initially the trainee observes 
the senior OGI camera operator and then eventually is observed by the 
senior OGI camera operator, and a final site survey test with zero 
missed persistent leaks. Additionally, the EPA proposed quarterly 
performance audits for OGI camera operators either by comparative 
monitoring or a review of video footage by a senior OGI camera 
operator, where the auditee must have zero missed persistent leaks and 
a technique that aligns with the site's monitoring plan. Auditees not 
meeting these criteria must be retrained. The EPA also proposed that 
operators would be required to repeat initial training after 12 months 
of inactivity.
    The EPA received numerous comments on all aspects of the proposed 
training requirements. Commenters stated that online training should be 
allowed for classroom training, and they recommended that periodic 
classroom training should be extended to every 2 or 3 years.\309\ 
Commenters also provided a broad range of recommendations on what the 
initial field training should

[[Page 74838]]

look like.\310\ The recommendations for initial training hours ranged 
from around 5 to 80 hours. Additionally, some commenters said the 
determination of suitability for independent monitoring should be based 
on observations and comparative monitoring, not on a set number of 
hours of training.\311\ Some commenters suggested reducing the final 
survey test to 1 hour.\312\ Commenters also suggested that requiring 
zero missed leaks during the final survey test was too stringent.\313\ 
Some commenters thought the OGI camera operator audits were 
unnecessary, while others thought they were too frequent or too long. 
There was a range of recommendations on what the audit frequency should 
be, including annual or a stepped up and down frequency based on 
performance.\314\ Additionally, commenters stated that requiring zero 
missed leaks during the audit was too stringent and that instead of a 
failed audit triggering automatic retraining, there should be an 
opportunity to counsel the auditee and let them try again.\315\ 
Commenters thought returning operators should only be required to take 
refresher level training, pass a performance audit, or pass the final 
survey test.\316\ Commenters also thought there should be some 
grandfathering of current OGI camera operators.\317\ Finally, 
commenters stated that there should be different performance audit and 
retraining requirements for small businesses and the Alaska North 
Slope.\318\
---------------------------------------------------------------------------

    \309\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0561, EPA-HQ-
OAR-2021-0317-0793, EPA-HQ-OAR-2021-0317-0808, EPA-HQ-OAR-2021-0317-
0814, EPA-HQ-OAR-2021-0317-0831, EPA-HQ-OAR-2021-0317-0954, and EPA-
HQ-OAR-2021-0317-1373.
    \310\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0463, EPA-HQ-
OAR-2021-0317-0561, EPA-HQ-OAR-2021-0317-0608, EPA-HQ-OAR-2021-0317-
0718, EPA-HQ-OAR-2021-0317-0749, EPA-HQ-OAR-2021-0317-0793, EPA-HQ-
OAR-2021-0317-0808, EPA-HQ-OAR-2021-0317-0816, EPA-HQ-OAR-2021-0317-
0831, and EPA-HQ-OAR-2021-0317-0934.
    \311\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0608 and EPA-HQ-
OAR-2021-0317-0718.
    \312\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0808 and EPA-HQ-
OAR-2021-0317-0831.
    \313\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0599, EPA-HQ-
OAR-2021-0317-0750, EPA-HQ-OAR-2021-0317-0782, EPA-HQ-OAR-2021-0317-
0793, EPA-HQ-OAR-2021-0317-0808, EPA-HQ-OAR-2021-0317-0817, and EPA-
HQ-OAR-2021-0317-0831.
    \314\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0463, EPA-HQ-
OAR-2021-0317-0561, EPA-HQ-OAR-2021-0317-0599, EPA-HQ-OAR-2021-0317-
0608, EPA-HQ-OAR-2021-0317-0718, EPA-HQ-OAR-2021-0317-0749, EPA-HQ-
OAR-2021-0317-0782, EPA-HQ-OAR-2021-0317-0808, EPA-HQ-OAR-2021-0317-
0831, and EPA-HQ-OAR-2021-0317-0916.
    \315\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0561, EPA-HQ-
OAR-2021-0317-0599, EEPA-HQ-OAR-2021-0317-0749, EPA-HQ-OAR-2021-
0317-0808, and EPA-HQ-OAR-2021-0317-0831.
    \316\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0463, EPA-HQ-
OAR-2021-0317-0608, EPA-HQ-OAR-2021-0317-0718, EPA-HQ-OAR-2021-0317-
0808, EPA-HQ-OAR-2021-0317-0816, and EPA-HQ-OAR-2021-0317-0831.
    \317\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0808 and EPA-HQ-
OAR-2021-0317-0831.
    \318\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0814, EPA-HQ-
OAR-2021-0317-0916, and EPA-HQ-OAR-2021-0317-1373.
---------------------------------------------------------------------------

    Based on these comments, the EPA is proposing specific revisions or 
clarifications related to the operator training requirements. In this 
action, the EPA is clarifying our intent to allow classroom training to 
be online or in-person and revising the classroom refresher training 
frequency to biennial (i.e., every 2 years). For the initial field 
training, the EPA is proposing 30 survey hours with a senior OGI camera 
operator and changing the final field test from one site to two survey 
hours. The EPA is also proposing to allow up to 10 percent missed leaks 
on the final survey test if there are more than 10 leaks found by the 
senior OGI camera operator during the final field test and is providing 
clarification on what happens if a trainee doesn't pass the final field 
test. In this instance, the senior OGI camera operator would discuss 
the failure with the trainee and provide instruction on improving 
performance, then allow the trainee to repeat the test. While the EPA 
is retaining quarterly operator audits, we are proposing to reduce the 
audit from four hours to two hours and allow up to 10 percent missed 
leaks if there are more than 10 leaks found by the senior OGI camera 
operator during the audit. While an auditee would still need to retrain 
following a failed audit, the EPA is proposing to reduce the amount of 
retraining from 25 site surveys to 16 survey hours and adding a 
requirement that the senior OGI camera operator counsel the auditee on 
the reasons for the failure and how to improve surveying techniques. 
However, if an auditee fails two consecutive audits, the auditee will 
have to complete the initial training again. The EPA is also proposing 
to reduce the amount of training required for OGI operators who have 
been inoperative for an extended period from the initial training 
requirements to the retraining requirements.
    Finally, the EPA is proposing to allow previous OGI experience to 
substitute for some of the initial training requirements within 
appendix K in order to recognize the experience of current OGI camera 
operators. Specifically, OGI camera operators with previous classroom 
training (either at a physical location or online) that covers the 
majority of the elements required by the initial classroom training 
required in appendix K prior to the finalization of appendix K will not 
need to complete the initial classroom training, but if the date of 
training is more than 2 years before the date that the appendix is 
finalized, the OGI camera operator will need to complete the biennial 
classroom training in lieu of the initial classroom training. Also, OGI 
camera operators who have 40 hours of experience over the 12 calendar 
months prior to the date that appendix K is finalized may substitute 
the retraining requirements, including the final monitoring survey 
test, for the initial field training requirements.
3. Senior OGI Camera Operator
    The EPA proposed that a senior OGI camera operator is a camera 
operator who has conducted a minimum of 500 site surveys over their 
career, including at least 20 site surveys in the past year, and who 
has taken or developed the initial classroom training. Commenters were 
concerned that there may be a lack of available senior OGI camera 
operators, especially in the period right after finalization of 
appendix K.\319\ Commenters also stated that the definition is too 
restrictive, and some were concerned there is no certification 
program.\320\ Some commenters also recommended that senior OGI 
operators should be removed from the auditing process since they are 
auditing and training others.\321\
---------------------------------------------------------------------------

    \319\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0599, EPA-HQ-
OAR-2021-0317-0750, EPA-HQ-OAR-2021-0317-0782, and EPA-HQ-OAR-2021-
0317-0831.
    \320\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0599, EPA-HQ-
OAR-2021-0317-0561, EPA-HQ-OAR-2021-0317-0608, EPA-HQ-OAR-2021-0317-
0718, EPA-HQ-OAR-2021-0317-0750, EPA-HQ-OAR-2021-0317-0802, and EPA-
HQ-OAR-2021-0317-0808.
    \321\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0749, and EPA-
HQ-OAR-2021-0317-0808.
---------------------------------------------------------------------------

    The EPA is proposing to change the definition of senior OGI camera 
operator to someone with 1400 survey hours over their career, including 
40 hours in the past year. The 1400 survey hours is consistent with the 
level that experienced operators had during the studies on operator 
experience performed at the Methane Emissions Technology Evaluation 
Center (METEC) test site.\322\ The study clearly showed a delineation 
of the detection capabilities of high experienced operators, with the 
high experienced operators detecting about 67 percent more leaks than 
other operators. The experience of the group of operators considered to 
be high experienced operators began at around 700 sites surveyed. The 
background

[[Page 74839]]

document for the METEC study estimated experience at about four sites 
per day, which equates to about two hours per site. Therefore, based on 
the data used in the study, 700 sites should equate to about 1400 hours 
on average. Additionally, the EPA is clarifying that the hours spent by 
the senior OGI camera operator performing comparative monitoring, 
either as part of initial training, retraining, or auditing other OGI 
camera operators, can be included when determining the senior OGI 
camera operator's experience both over their career and the past 12 
months.
---------------------------------------------------------------------------

    \322\ See Document ID No. EPA-HQ-OAR-2021-0317-0076.
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4. Dwell Time
    The EPA proposed that during a survey, OGI camera operators should 
view equipment from multiple angles. For each angle, the dwell time, 
the active time the operator is looking for potential leaks when the 
scene is in focus and steady, would need to be a minimum of 5 seconds 
per component in the field of view. Some commenters stated that there 
is no need to specify a dwell time, while other commenters said that 
the dwell time should be shorter.\323\ Still other commenters stated 
that the dwell time requirement should be based on the scene and not on 
a per component basis.\324\
---------------------------------------------------------------------------

    \323\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0570, EPA-HQ-
OAR-2021-0317-0599, EPA-HQ-OAR-2021-0317-0463, EPA-HQ-OAR-2021-0317-
0608, EPA-HQ-OAR-2021-0317-0718, EPA-HQ-OAR-2021-0317-0782, EPA-HQ-
OAR-2021-0317-0816, EPA-HQ-OAR-2021-0317-0808, EPA-HQ-OAR-2021-0317-
0831, EPA-HQ-OAR-2021-0317-0916, and EPA-HQ-OAR-2021-0317-0954.
    \324\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0561, EPA-HQ-
OAR-2021-0317-0816, and EPA-HQ-OAR-2021-0317-0954.
---------------------------------------------------------------------------

    The EPA is proposing to change the dwell time per angle to two 
seconds per component in the field of view. This aligns closely with 
the estimated time to complete a monitoring survey in the analysis 
performed for onshore natural gas processing plants for the proposed 
NSPS OOOOb.\325\ The EPA based that analysis on data provided by OGI 
camera operators. The EPA believes that two seconds per component would 
provide enough time to determine whether a leak is present, and it is 
expected that a trained OGI camera operator would be aware of 
situations that necessitate dwelling longer than the minimum required 
time.
---------------------------------------------------------------------------

    \325\ See Chapter 10 of the November 2021 TSD at Document ID No. 
EPA-HQ-OAR-2021-0317-0166.
---------------------------------------------------------------------------

5. Other Changes
    The EPA proposed that OGI camera operators must take 5-minute rest 
breaks after 20 minutes of continuous surveying. This proposed 
requirement is the same as the requirement for opacity observations in 
EPA Method 9 of 40 CFR part 60 appendix A-4. Commenters were divided 
over this requirement. Some commenters agreed with the principal of 
rest breaks while requesting additional flexibility or longer surveying 
times between breaks. Others felt it was unnecessary to mandate rest 
breaks.\326\ Rest breaks are an appropriate requirement for OGI camera 
operators because physical, mental, and eye fatigue are concerns with 
continuous field operation of OGI cameras. The EPA is proposing to 
update the requirement for rest breaks to once every 30 minutes, as one 
commenter \327\ noted that this makes tracking breaks easier. The EPA 
does not believe that changing the continuous survey period from 20 
minutes to 30 minutes will have a detrimental effect on an operator's 
ability to see leaks, and as such, is proposing to update the 
requirement to ease the burden on operators performing surveys. The EPA 
is not proposing a change in the length of the rest break. No comments 
were received on the specific length of the rest break. The EPA also 
notes that operators may perform tasks related to the survey, such as 
documentation, during rest breaks; the rest break is solely a break 
from actively imaging components.
---------------------------------------------------------------------------

    \326\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0561, EPA-HQ-
OAR-2021-0317-0599, EPA-HQ-OAR-2021-0317-0608, EPA-HQ-OAR-2021-0317-
0718, EPA-HQ-OAR-2021-0317-0749, EPA-HQ-OAR-2021-0317-0750, EPA-HQ-
OAR-2021-0317-0782, EPA-HQ-OAR-2021-0317-0793, EPA-HQ-OAR-2021-0317-
0808, EPA-HQ-OAR-2021-0317-0814, EPA-HQ-OAR-2021-0317-0816, EPA-HQ-
OAR-2021-0317-0954, and EPA-HQ-OAR-2021-0317-1373.
    \327\ See Document ID No. EPA-HQ-OAR-2021-0317-0561.
---------------------------------------------------------------------------

    The EPA proposed that OGI cameras must be capable of imaging 
methane emissions of 17 grams per hour(g/hr) and butane emissions of 
18.5 g/hr at a viewing distance of 2 meters and a delta-T of 5 [deg]C 
in an environment of calm wind conditions. Commenters stated that gases 
other than butane should be used for certification of cameras.\328\ 
Additionally, some commenters stated that the emission rates in the 
camera certification should be the same as in NSPS OOOOa.\329\ While 
the EPA does not agree that the camera certification should be the same 
as what is in NSPS OOOOa because we have learned more about the 
detection capabilities of OGI cameras since that time, we are proposing 
to change the butane requirement to a choice between propane or butane 
and noting that referencing subparts may provide specifications for 
other gases. The EPA is also clarifying that the initial certification 
testing, as well as the operating window development testing, can be 
performed by the owner or operator, the camera manufacturer, or a third 
party.
---------------------------------------------------------------------------

    \328\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0599 and EPA-HQ-
OAR-2021-0317-0808.
    \329\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0782 and EPA-HQ-
OAR-2021-0317-0808.
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    The EPA proposed that the response factors used when determining 
whether an OGI camera would be able to image the components in gaseous 
emissions would need to come from peer reviewed publications. 
Commenters requested that the EPA develop guidance on how to develop 
response factors and stated that the response factors should be able to 
be developed by manufacturers without the requirement for peer reviewed 
publication.\330\ The EPA agrees with these comments, and as such, is 
proposing to remove the requirement for peer reviewed publications. 
Guidance for developing response factors is being provided as annex 1 
to appendix K.
---------------------------------------------------------------------------

    \330\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0808 and EPA-HQ-
OAR-2021-0317-0831.
---------------------------------------------------------------------------

    The EPA proposed that when a leak is found with OGI, the OGI camera 
operator must take a video clip of the leak. As requested by 
commenters, this requirement is being updated to allow a photograph of 
leaks as an option in lieu of video clips.\331\ Additionally, as 
requested by a commenter, the EPA is proposing to allow the option for 
full videos of the surveys to be retained in lieu of video clips of 
leaks.\332\
---------------------------------------------------------------------------

    \331\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0463, EPA-HQ-
OAR-2021-0317-0599, EPA-HQ-OAR-2021-0317-0808, EPA-HQ-OAR-2021-0317-
0814 and EPA-HQ-OAR-2021-0317-1373.
    \332\ See Document ID No. EPA-HQ-OAR-2021-0317-0816.
---------------------------------------------------------------------------

    The EPA is proposing to add a definition of monitoring survey, 
which means imaging equipment with an OGI camera at one site on one 
day. Changing site location or changing the day of imaging would 
constitute a new monitoring survey. This definition is needed to help 
clarify some of the requirements related to recordkeeping for 
monitoring surveys.
    Finally, the EPA is also making a number of other clarifications 
and minor edits based on comments received during the November 2021 
proposal.

C. Summary of Proposed Requirements

    In this action, the EPA is proposing a protocol for the use of OGI 
as appendix K. As part of the development of appendix K, the EPA 
conducted an extensive literature review on the technology development 
as well as

[[Page 74840]]

observations on current application of OGI technology. Approximately 
150 references identify the technology, applications, and limitations 
of OGI. The EPA also commissioned multiple laboratory studies and OGI 
technology evaluations. Additionally, on November 9 and 10, 2020, the 
EPA held a virtual stakeholder workshop to gather input on development 
of a protocol for the use of OGI. The information obtained from these 
efforts was used to develop the TSD for appendix K, which provides 
technical analyses, experimental results, and other supplemental 
information used to evaluate and develop standardized procedures for 
the use of OGI technology in monitoring for fugitive emissions of VOCs, 
HAP, and methane from industrial environments.\333\
---------------------------------------------------------------------------

    \333\ See Document ID No. EPA-HQ-OAR-2021-0317-0079.
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    The EPA notes that while this protocol is being proposed for use at 
onshore natural gas processing plants in this action at the proposed 40 
CFR 60.5400b and 40 CFR 60.5400c, the applicability of the protocol is 
broader. The protocol is applicable to facilities when specified in a 
referencing subpart to help determine the presence and location of 
leaks; it is not currently applicable for use in direct emission rate 
measurements from sources. The protocol may be applied, when 
referenced, to surveys of process equipment using OGI cameras where the 
majority of compounds (>75 percent by weight) in the emissions streams 
have a response factor of at least 0.25 when compared to the response 
factor of propane. The OGI camera must also be capable of detecting (or 
producing a detectable image of) methane emissions of 17 g/hr and 
either butane emissions of 5.0 g/hr or propane emissions of 18 g/hr at 
a viewing distance of 2 meters and a delta-T of 5 [deg]C in an 
environment of calm wind conditions around 1 meter per second or less. 
Verification that the OGI camera meets these criteria may be performed 
by the owner or operator, the camera manufacturer, or a third party. 
The supplies necessary for conducting the verification are described in 
section 6.2 of the proposed appendix.
    Field conditions, such as the viewing distance to the component to 
be monitored, wind speed, ambient air temperature, and the background 
temperature, have the potential to impact the ability of the OGI camera 
operator to detect a leak. Because it is important that the OGI camera 
has been tested under the full range of expected field conditions in 
which the OGI camera will be used, an operating envelope must be 
established for field use of the OGI camera. Imaging must not be 
performed when the conditions are outside of the developed operating 
envelope. Operating envelopes are specific to each model of OGI camera 
and can be developed by the owner or operator, the camera manufacturer, 
or a third party. To develop the operating envelope, methane gas is 
released at a set mass rate and wind speed, viewing distance, and 
delta-T (the temperature differential of the background and the 
released gas) are all varied to determine the conditions under which a 
leak can be imaged. For purposes of developing the operating envelope, 
a leak is considered able to be imaged if three out of four observers 
can see the leak. Once the operating envelope is developed using 
methane, the testing is repeated with either butane or propane gas. The 
operating envelope for the OGI camera is the more restrictive operating 
envelope developed between the different test gases.
    The operating envelope must be confirmed for all potential 
configurations that could impact the detection limit of the OGI camera. 
In response to the November 2021 proposal, several commenters suggested 
that the operating envelope determination requirements should be 
streamlined. For example, if a configuration is established and 
confirmed, another configuration that is inherently more sensitive 
should be allowed without additional testing. Commenters also requested 
a more defined and acceptable list of configurations be provided based 
on the technology's capabilities, not user preferences.\334\ The EPA 
does not currently have enough data or empirical evidence to provide a 
complete list of possible configurations for all the available 
commercial OGI cameras (taking into account future possible 
configurations) or a definitive ranking of which configurations are 
more stringent than other. The EPA is requesting comment on this topic 
and seeking any empirical data that could be used to create such a 
defined ranking of configurations. Additionally, one commenter 
suggested that instead of having different operating envelopes for 
different situations and having to decide which envelope to use, the 
OGI camera operator should conduct a daily camera demonstration each 
day prior to imaging to determine the maximum distance at which the OGI 
camera operator should image for that day.\335\ The EPA believes that 
this type of determination would be more difficult and costly than 
creating an operating envelope, as it would require OGI camera 
operators to have necessary gas supplies on hand and take time to do 
this determination daily, or potentially multiple times a day. 
Nevertheless, the EPA is requesting comment on this suggestion, as well 
as how such a demonstration could be used if conditions on the site 
change throughout the day, at what point would the changed conditions 
necessitate repeating the demonstration, and how changes in the 
background in different areas of the site (such as to affect the delta-
T) would be factored into such a demonstration.
---------------------------------------------------------------------------

    \334\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0604 and EPA-HQ-
OAR-2021-0317-0954.
    \335\ See Document ID No. EPA-HQ-OAR-2021-0317-0561.
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    The EPA is proposing that each site would have a monitoring plan 
that describes the procedures for conducting a monitoring survey. One 
monitoring plan can be used for multiple sites, as long as the plan 
contains the relevant information for each site. The monitoring plan 
must contain procedures for a daily verification check, ensuring that 
the monitoring survey is performed only when conditions in the field 
are within the operating envelope, monitoring all the components 
regulated by the referencing subpart within the unit or area, viewing 
the components with the camera, operator rest breaks, documenting 
surveys, and quality assurance.
    Delta-T is a crucial variable in determining whether it is possible 
to see a leak. Without an adequate delta-T, it will be difficult, or 
even impossible to see a leak, no matter how big the leak is. The EPA 
is proposing that the monitoring plan must describe how the operator 
will ensure an adequate delta-T is present in order to view potential 
gaseous emissions, e.g., using a delta-T check function built into the 
features of the OGI camera or using a background temperature reading in 
the OGI camera field of view. In response to the November 2021 
proposal, a commenter stated guidance should be added for operators who 
are using a background temperature reading in the OGI camera field of 
view.\336\ The EPA is requesting comment on ways that an OGI camera 
operator can ensure an adequate delta-T exists during monitoring 
surveys for cameras that do not have a built-in delta-T check function.
---------------------------------------------------------------------------

    \336\ See Document ID No. EPA-HQ-OAR-2021-0317-0719.
---------------------------------------------------------------------------

    The EPA is proposing that a component must be imaged from at least

[[Page 74841]]

two different angles, and the OGI camera operator must dwell on each 
angle for a minimum of 2 seconds per component in the field of view, 
where dwell time is defined as the time the scene is steady and in 
focus and the operator is actively viewing the scene. The operator may 
reduce the dwell time for complex scenes based on the monitoring area 
and number of components in the subsection as prescribed in Table 14-1 
of the appendix; use of this table is only required when an operator 
wants to reduce the dwell time from the minimum 2 second per component 
dwell time. In response to the November 2021 proposal, commenters 
suggested that dwell time should be based on the scene, not on a per 
component basis. Additionally, commenters suggested further defining 
the scene as ``simple'' or ``complex'' with a greater dwell time for 
``complex'' scenes.\337\ The EPA is concerned with creating blanket 
dwell times for scenes, as scenes can vary in complexity within these 
categories, and an operator would need to look at scenes with more 
components longer than a scene with fewer components. Additionally, the 
EPA does not believe it is possible to describe every possible scene in 
order to create bins for ``simple'' and ``complex'' scenes that would 
be inclusive of all scenes an OGI camera operator might encounter in 
the field. However, the EPA is soliciting comment on how dwell time 
could be based on the scene while still accounting for the differences 
in the complexity of scenes or ways to create bins for ``simple'' and 
``complex'' scenes. The EPA is also soliciting comment on ways to 
similarly achieve the goal of ensuring that OGI camera operators survey 
a scene for an adequate amount of time to ensure there are no leaks 
from any components in the field of view without specifying a dwell 
time.
---------------------------------------------------------------------------

    \337\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0561, EPA-HQ-
OAR-2021-0317-0604, EPA-HQ-OAR-2021-0317-0816, and EPA-HQ-OAR-2021-
0317-0954.
---------------------------------------------------------------------------

    Physical, mental, and eye fatigue are concerns with continuous 
field operation of OGI cameras. The EPA is proposing that OGI camera 
operators must take a rest break after surveying continuously for a 
period of 30 minutes. In response to the November 2021 proposal, 
commenters suggested that this was an unnecessary requirement. The EPA 
is aware that continuously surveying for long periods can lead to 
decreased detection of leaks. However, the EPA has heard anecdotally 
that this may have more to do with the number of hours the OGI camera 
operator has surveyed during the day, such that it is more appropriate 
to limit the hours of surveying per day than it is to mandate rest 
breaks at a set frequency. The EPA is seeking any empirical data on the 
topic of the necessity of rest breaks when conducting OGI surveys or 
the link between operator performance and length of survey period.
    The EPA is proposing that the facility or company performing the 
OGI surveys must have a training plan which ensures and monitors the 
proficiency of the OGI camera operators. If the facility does not 
perform its own OGI monitoring, the facility must ensure that the 
training plan for the company performing the OGI surveys adheres to 
this requirement. The proposed appendix K prescribes a multi-faceted 
approach to training. Training includes classroom instruction (either 
online or at a physical location) both initially and biennially on the 
OGI camera and external devices, monitoring techniques, best practices, 
process knowledge, and other regulatory requirements related to leak 
detection that are relevant to the facility's OGI monitoring efforts. 
Prior to conducting monitoring surveys, camera operators must 
demonstrate proficiency with the OGI camera. The initial field training 
includes a minimum of 30 survey hours with OGI where trainees first 
observe the techniques and methods of a senior OGI camera operator and 
then eventually perform monitoring surveys independently with a senior 
OGI camera operator present to provide oversight. The trainee must then 
pass a final monitoring survey test of at least two hours. If there are 
10 or more leaks identified by the senior OGI operator, the trainee 
must achieve less than 10 percent missed persistent leaks relative to 
the senior OGI camera operator to be considered authorized for 
independent survey execution. If there are less than 10 leaks 
identified by the senior OGI operator, the trainee must achieve zero 
missed persistent leaks relative to the senior OGI camera operator to 
be considered authorized for independent survey execution. If the 
trainee doesn't pass the monitoring survey test, the senior OGI camera 
operator must discuss the reasons for the failure with the trainee and 
provide instruction/correction on improving the trainee's performance, 
following which the trainee may repeat the final test.
    The EPA is proposing that performance audits for all OGI camera 
operators must occur on a quarterly basis and can be conducted either 
by comparative monitoring or video review by a senior OGI camera 
operator. If the senior OGI camera operator finds that the survey 
techniques during the video review do not match those described in the 
monitoring plan, then the camera operator being audited will need to be 
retrained. Additionally, if there are 10 or more leaks identified by 
the senior OGI operator, the camera operator being audited must achieve 
less than 10 percent missed persistent leaks relative to the senior OGI 
camera operator. If there are less than 10 leaks identified by the 
senior OGI operator, the camera operator being audited must achieve 
zero missed persistent leaks relative to the senior OGI camera 
operator. Retraining consists of a discussion of the reasons for the 
failure with the OGI operator being audited and techniques to improve 
performance; a minimum of 16 survey training hours; and a final 
monitoring survey test. If an OGI operator requires retraining in two 
consecutive quarterly audits, the OGI operator must repeat the initial 
training requirements. In response to the November 2021 proposal, 
commenters stated that there should be no performance audit 
requirements for senior OGI camera operators because senior OGI camera 
operators are responsible for training and auditing other OGI camera 
operators. The EPA believes that it is important to verify the 
performance of all OGI camera operators, even the most experienced 
operators, on an ongoing basis. Nevertheless, the EPA is requesting 
comment on whether there should be a reduced performance audit 
frequency for certain OGI camera operators, and if so, who should 
qualify for a reduced frequency, what the reduced frequency should be, 
and the basis for the reduced frequency.
    Previous experience with OGI camera operation can be substituted 
for some of the initial training requirements. OGI camera operators 
with previous classroom training (either at a physical location or 
online) that covers the majority of the elements required by the 
initial classroom training required in appendix K prior to the 
finalization of appendix K do not need to complete the initial 
classroom training, but if the date of certification is more than 2 
years before the publication date of the final rule, the biennial 
classroom training must be completed in lieu of the initial classroom 
training. OGI camera operators who have 40 hours of experience over the 
12 calendar months prior to the date of publication of the final rule 
may substitute the retraining requirements, including the final 
monitoring survey test, for the initial field training requirements.
    Recordkeeping is an important compliance assurance measure. The 
proposed appendix K requires records

[[Page 74842]]

to be retained in hard copy or electronic form. Records include the 
site monitoring plan, operating envelope limitations, data supporting 
the initial OGI camera performance verification and development of the 
operating envelope, the training plan for OGI camera operators, OGI 
camera operator training and auditing records, records necessary to 
verify senior OGI camera operator status, monitoring survey records, 
quality assurance verification videos for each operator, and 
maintenance and calibration records. Some of the records required by 
the proposed appendix K are not required to be kept onsite as long as 
the owner or operator can easily access these records and can make the 
records available for review if requested by the Administrator.

VII. 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 OOOOb and EG OOOOc will reduce about 36 
million short tons of methane emissions (810 million tons 
CO2 Eq.), 9.7 million short tons of VOC emissions, and 390 
thousand short tons of HAP emission from facilities that are 
potentially affected by this proposal. The EPA projected regulatory 
impacts beginning in 2023 as that year represents the first full year 
of implementation of the proposed NSPS OOOOb. The EPA assumes that 
emissions impacts of the proposed EG OOOOc will begin in 2026. The EPA 
projected 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, though the EPA is soliciting comment on whether information 
exists to better characterize the likely effects beyond 2035.
    As noted in section I of this preamble, the updated analysis not 
only incorporates the new provisions put forth in the supplemental 
proposal (in addition to the elements of the November 2021 proposal 
that are unchanged), but also includes key updates to assumptions and 
methodologies that impact both the baseline and policy scenarios. 
Accordingly, these estimates of air impacts are not directly comparable 
to corresponding estimates presented in the November 2021 proposal.

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 VIII.D of this preamble. 
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 equivalent annualized value, or EAV, of the regulatory 
compliance cost associated with the proposed NSPS OOOOb and EG OOOOc 
over the 2023 to 2035 period was estimated to be $1.4 billion per year 
using a 3-percent discount rate and $1.4 billion using a 7-percent 
discount rate. The corresponding estimates of the present value (PV) of 
compliance costs were $14 billion (in 2019 dollars) using a 3-percent 
discount rate and $12 billion using a 7-percent discount rate. These 
estimates include the producer revenues associated with the projected 
increase in the recovery of saleable natural gas, using the 2022 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. Estimates of the value of the 
recovered product have been included in previous regulatory analyses as 
offsetting compliance costs and are appropriate to include when 
assessing the societal cost of a regulation. If the recovery of 
saleable natural gas is not accounted for, the EAV of the regulatory 
compliance costs of the proposed rule over the 2023 to 2035 period were 
estimated to be $1.8 billion per year using a 3-percent discount rate 
and $1.8 billion per year using a 7-percent discount rate. The PV of 
these costs were estimated to be $19 billion using a 3-percent discount 
rate and $15 billion using a 7-percent discount rate.

D. What are the economic and employment impacts?

    The EPA conducted an economic impact and distributional analysis 
for this proposal, as detailed in section 4 of the RIA for this 
supplemental proposal. To provide a partial measure of the economic 
consequences of the proposed NSPS OOOOb and EG OOOOc, the EPA developed 
a pair of single-market, static partial-equilibrium analyses of 
national crude oil and natural gas markets. We implemented the pair of 
single-market analyses instead of a coupled market or general 
equilibrium approach to provide broad insights into potential national-
level market impacts while providing maximum analytical transparency. 
We estimated the price and quantity impacts of the proposed NSPS OOOOb 
and EG OOOOc on crude oil and natural gas markets for a subset of years 
within the time horizon analyzed in the RIA. The models are 
parameterized using production and price data from the U.S. Energy 
Information Administration and supply and demand elasticity estimates 
from the economics literature.
    The RIA projects that regulatory costs are at their highest in 
2026, the first year the requirements of both the proposed NSPS OOOOb 
and EG OOOOc are assumed to be in effect and will represent the year 
with the largest market impacts based upon the partial equilibrium 
modeling. We estimated that the proposed rule could result in a maximum 
decrease in annual natural gas production of about 358 million Mcf in 
2026 (or about 1.00 percent of natural gas production) with a maximum 
price increase of $0.07 per Mcf (or about 2.35 percent). We estimated 
the maximum annual reduction in crude oil production would be about 21 
million barrels (or about 0.52 percent of crude oil production) with a 
maximum price increase of about $0.10 per barrel (or less than 0.16 
percent).
    Before 2026, the modeled market impacts are much smaller than the 
2026 impacts as only the incremental requirements under the proposed 
NSPS OOOOb are assumed to be in effect. As regulatory costs are 
projected to decline after 2026, the modelled market impacts for years 
after 2026 are smaller than the peaks estimated for 2026. Please see 
section 4.1 of the RIA for more detail on the formulation and 
implementation of the model as well as a discussion of several 
important caveats and limitations associated with the approach.
    As discussed in the RIA for this proposal, employment impacts of 
environmental regulations are generally composed of a mix of potential 
declines and gains in different areas of the economy over time. 
Regulatory employment impacts can vary across occupations, regions, and 
industries; by labor and product demand and supply elasticities; and in 
response to other labor market conditions. Isolating such impacts is a 
challenge, as they are difficult to disentangle from employment impacts 
caused by a wide variety of ongoing, concurrent economic changes.
    The oil and natural gas industry directly employs approximately 
140,000 people in oil and natural gas extraction, a figure which varies 
with market prices

[[Page 74843]]

and technological change and employs a large number of workers in 
related sectors that provide materials and services.\338\ As indicated 
above, the proposed NSPS OOOOb and EG OOOOc are projected to cause 
small changes in oil and natural gas production and prices. As a 
result, demand for labor employed in oil and natural gas-related 
activities and associated industries might experience adjustments as 
there may be increases in compliance-related labor requirements as well 
as changes in employment due to quantity effects in directly regulated 
sectors and sectors that consume oil and natural gas products.
---------------------------------------------------------------------------

    \338\ Employment figure drawn from the Bureau of Labor 
Statistics Current Employment Statistics for NAICS code 211.
---------------------------------------------------------------------------

E. What are the benefits of the proposed standards?

    To satisfy the requirement of E.O. 12866 and to inform the public, 
the EPA estimated the climate and health benefits due to the emissions 
reductions projected under the proposed NSPS OOOOb and EG OOOOc. The 
EPA expects climate and health benefits due to the emissions reductions 
projected under the proposed NSPS OOOOb and EG OOOOc. The EPA estimated 
the climate 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 E.O. 13990 (IWG 2021)'' 
published in February 2021 by the Interagency Working Group on the 
Social Cost of Greenhouse Gases (IWG). The SC-CH4 is the 
monetary value of the net harm to society associated with a marginal 
increase in emissions in a given year, or the benefit of avoiding that 
increase. In principle, SC-CH4 includes the value of all 
climate change impacts, including (but not limited to) changes in net 
agricultural productivity, human health effects, property damage from 
increased flood risk and natural disasters, disruption of energy 
systems, risk of conflict, environmental migration, and the value of 
ecosystem services. The SC-CH4 therefore, reflects the 
societal value of reducing emissions of the gas in question by one 
metric ton and is the theoretically appropriate value to use in 
conducting benefit-cost analyses of policies that affect CH4 
emissions.
    The interim estimates of the social cost of methane and other 
greenhouse gases (collectively referred to as the social cost of 
greenhouse gases (SC-GHG)) presented in the February 2021 Technical 
Support Document (TSD) (IWG 2021) were developed over many years, using 
a transparent process, peer-reviewed methodologies, the best science 
available at the time of that process, and with input from the public. 
As a member of the IWG involved in the development of the February 2021 
TSD, the EPA agrees that the interim SC-GHG estimates continue to 
represent at this time the most appropriate estimate of the SC-GHG 
until revised estimates have been developed reflecting the latest, 
peer-reviewed science. However, while the IWG's SC-GHG work under E.O. 
13990 continues, the RIA accompanying this proposal the EPA presents a 
sensitivity analysis of the monetized climate benefits using a set of 
SC-CH4 estimates that incorporates recent research 
addressing recommendations of the National Academies of Sciences, 
Engineering, and Medicine (2017).
    We invite the public to comment on both the sensitivity analysis of 
the monetized climate benefits and the accompanying external review 
draft technical report that the EPA has prepared that explains the 
methodology underlying the newer set of SC-CH4 estimates. 
This report is also included as supporting material for the RIA in the 
docket.\339\ However, we emphasize that the monetized benefits analysis 
is entirely distinct from the statutory BSER determinations proposed 
herein and is presented solely for the purposes of complying with E.O. 
12866. As discussed in more detail in the November 2021 proposal and 
earlier in this notice, the EPA weighed the relevant statutory factors 
to determine the appropriate proposed standards and did not rely on the 
monetized benefits analysis for purposes of determining the standards. 
E.O. 12866 separately requires the EPA to perform a benefit-cost 
analysis, including monetizing costs and benefits where practicable, 
and the EPA has conducted such an analysis. The monetized climate 
benefits calculated using the SC-CH4 are included in the 
benefit-cost analysis, and thus, as is generally the case with any 
analytical methods, data, or results associated with RIAs, the EPA 
welcomes the opportunity to continually improve its understanding 
through public input on these estimates.
---------------------------------------------------------------------------

    \339\ For more information about the development of these 
estimates, see www.epa.gov/environmental-economics/scghg.
---------------------------------------------------------------------------

    The EPA estimated the PV of the climate benefits over the 2023 to 
2035 period to be $48 billion at a 3-percent discount rate. The EAV of 
these benefits is estimated to be $4.5 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 NSPS OOOOb and EG OOOOc, 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 screening analysis in Appendix C of the RIA based on 
modeled oil and natural gas VOC contributions to ozone concentrations 
as they occurred in 2017 and do not include the results of this 
analysis in the estimate of benefits and net benefits projected from 
this proposal.

VIII. 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 of the 
Supplemental Proposal for the 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.

B. Paperwork Reduction Act (PRA)

    The information collection activities in the proposed amendments 
for 40 CFR part 60, subparts OOOOb and OOOOc,

[[Page 74844]]

have been submitted for approval to the OMB under the PRA. The ICR 
document that the EPA prepared has been assigned OMB Control No. 2060-
0721 and EPA ICR number 2523.05. You can find a copy of the ICR in the 
docket for this rule, and it is briefly summarized here. As noted in 
section IV.N of this supplemental preamble, draft versions of the 
proposed templates for the semiannual and annual reports for these 
subparts are included in the docket for this action,\340\ and the EPA 
specifically requests comment on the content, layout, and overall 
design of the templates.
---------------------------------------------------------------------------

    \340\ See Part_60_Subpart_OOOOb_60.5420b(b)_Annual_Report.xlsm 
and Part_60_Subpart_OOOOb_60.5422b(b)_Semiannual_Report.xlsx, 
available in the docket for this action.
---------------------------------------------------------------------------

40 CFR Part 60, Subpart OOOOb

    This ICR reflects the EPA's proposed NSPS OOOOb for a wide range of 
emissions sources in the Crude Oil and Natural Gas source category. The 
information collected will be used by the EPA and delegated state and 
local agencies to determine the compliance status of affected 
facilities subject to the rule.
    Respondents/affected entities: Oil and natural gas operators and 
owners; approved third-party notifiers.
    Respondent's obligation to respond: Mandatory.
    Estimated number of respondents: 1,849.
    Frequency of response: Varies depending on affected facility.\341\
---------------------------------------------------------------------------

    \341\ The specific frequency for each information collection 
activity within this request is shown in Tables 1a through 1d of the 
Supporting Statement in the public docket.
---------------------------------------------------------------------------

    Total estimated burden: 883,625 hours (per year). Burden is defined 
at 5 CFR 1320.3(b).
    Total estimated cost: $58,535,262($2019) (per year), which includes 
$12,182,846 in capital costs.

40 CFR Part 60, subpart OOOOc

    This rule does not directly impose specific requirements on oil and 
natural gas facilities located in states or areas of Indian country. 
The rule also does not impose specific requirements on tribal 
governments that have affected facilities located in their area of 
Indian country. This rule does impose specific requirements on state 
governments with affected oil and natural gas facilities. The 
information collection requirements are based on the recordkeeping and 
reporting burden associated with developing, implementing, and 
enforcing a plan to limit GHG emissions from existing sources in the 
oil and natural gas sector. These recordkeeping and reporting 
requirements are specifically authorized by CAA section 114 (42 U.S.C. 
7414). All information submitted to the EPA pursuant to the 
recordkeeping and reporting requirements for which a claim of 
confidentiality is made is safeguarded according to Agency policies set 
forth in 40 CFR part 2, subpart B.
    The annual burden for this collection of information for the states 
(averaged over the first 3 years following promulgation) is estimated 
to range from 55,467 to 69,333 hours at a total annual labor cost of 
between $7 to $8.8 million. The annual burden for the Federal 
government associated with the state collection of information 
(averaged over the first 3 years following promulgation) is estimated 
to be 22,520 hours at a total annual labor cost of $1,399,930. The 
annual burden for industry (averaged over the first 3 years following 
promulgation) is estimated to be 2.2 million hours at a total annual 
labor cost of $166 million. We realize, however, that some facilities 
may not incur these costs within the first 3 years and may incur them 
during the fourth or fifth year instead. Therefore, this ICR presents a 
conservatively high burden estimate for the initial 3 years following 
promulgation of the proposed emission guidelines. Burden is defined at 
5 CFR 1320.3(b).
    Respondents/affected entities: States with one or more designated 
facilities covered under subpart OOOOc.
    Respondent's obligation to respond: Mandatory.
    Estimated number of respondents: 50.
    Frequency of response: Once.
    Total estimated burden: 69,333 hours (per year). Burden is defined 
at 5 CFR 1320.3(b).
    Total estimated cost: $8,822,020 (per year), which includes $36,750 
in capital costs.
    An Agency may not conduct or sponsor, and a person is not required 
to respond to, a collection of information unless it displays a 
currently valid OMB control number. The OMB control numbers for the 
EPA's regulations in 40 CFR are listed in 40 CFR part 9. Submit your 
comments on the Agency's need for this information, the accuracy of the 
provided burden estimates and any suggested methods for minimizing 
respondent burden to the EPA using the docket identified at the 
beginning of this rule. The EPA will respond to any ICR-related 
comments in the final rule. Written comments and recommendations for 
the proposed information collection should be sent within 30 days of 
publication of this notice to www.reginfo.gov/public/do/PRAMain. Find 
this particular information collection by selecting ``Currently under 
30-day Review--Open for Public Comments'' or by using the search 
function. Since OMB is required to make a decision concerning the ICR 
between 30 and 60 days after receipt, OMB must receive comments no 
later than January 5, 2023.

C. Regulatory Flexibility Act (RFA)

    Pursuant to section 603 of the RFA, the EPA prepared an initial 
regulatory flexibility analysis (IRFA) that examined the impact of the 
proposed rule on small entities along with regulatory alternatives that 
could minimize that impact. The complete IRFA is available for review 
in the RIA (see Section 4.3) and the EPA is soliciting comment on the 
presentation of its analysis of the impacts on small entities, 
particularly if there is value in presenting more granular information 
beyond a focus on entities above and below the SBA size 
classifications.
    As required by section 609(b) of the RFA, the EPA also convened a 
Small Business Advocacy Review (SBAR) Panel to obtain advice and 
recommendations from small entity representatives that potentially 
would be subject to the rule's requirements. The SBAR Panel evaluated 
the assembled materials and small-entity comments on issues related to 
elements of an IRFA. A copy of the full SBAR Panel Report is available 
in the rulemaking docket.
    As required by section 604 of the RFA, the EPA will prepare a final 
regulatory flexibility analysis (FRFA) for this action as part of the 
final rule. The FRFA will address the issues raised by public comments 
on the IRFA.

D. Unfunded Mandates Reform Act (UMRA)

    The NSPS contains a federal mandate under UMRA, 2 U.S.C. 1531-1538, 
that may result in expenditures of $100 million or more for state, 
tribal, and local governments, in the aggregate, or the private sector 
in any one year. Accordingly, the EPA has prepared under section 202 of 
the UMRA a written statement of the benefit-cost analysis, which can be 
found in Section VII of this preamble, and in Chapter 1 of the RIA.
    Consistent with section 205, the EPA has identified and considered 
a reasonable number of regulatory alternatives. These alternatives are 
described in Section IV of this preamble.
    The EG is proposed under CAA section 111(d) and does not impose any 
direct compliance requirements on designated facilities, apart from the

[[Page 74845]]

requirement for states to develop state plans. As explained in section 
XIV.G. of the November 2021 proposal \342\ and section V of this 
supplemental proposal, the EG also does not impose specific 
requirements on tribal governments that have designated facilities 
located in their area of Indian country. The burden for states to 
develop state plans following promulgation of the rule is estimated to 
be below $100 million in any one year. Thus, the EG is not subject to 
the requirements of section 203 or section 205 of the UMRA.
---------------------------------------------------------------------------

    \342\ See 86 FR 63256 (November 15, 2021).
---------------------------------------------------------------------------

    The NSPS and EG are also not subject to the requirements of section 
203 of UMRA because, as described in 2 U.S.C. 1531-38, they contain no 
regulatory requirements that might significantly or uniquely affect 
small governments. Specifically, for the EG the state governments to 
which rule requirements apply are not considered small governments. In 
light of the interest among governmental entities, the EPA conducted 
pre-proposal outreach with national organizations representing states 
and tribal governmental entities while formulating the proposed rule as 
discussed in section VII of the November 2021 proposal.\343\ 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 states and tribes. 
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.
---------------------------------------------------------------------------

    \343\ See 86 FR 63145 (November 15, 2021).
---------------------------------------------------------------------------

E. Executive Order 13132: Federalism

    Under Executive Order 13132, the EPA may not issue an action that 
has federalism implications, that imposes substantial direct compliance 
costs, and that is not required by statute, unless the Federal 
Government provides the funds necessary to pay the direct compliance 
costs incurred by state and local governments, or the EPA consults with 
state and local officials early in the process of developing the 
proposed action.
    The proposed NSPS OOOOb and proposed EG OOOOc do not have 
federalism implications. These actions will not have substantial direct 
effects on the states as defined in the Executive Order, on the 
relationship between the Federal Government and the States, or on the 
distribution of power and responsibilities among the various levels of 
government.

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 E.O. 13175. See 65 FR 67249 (November 9, 2000). As stated 
in the November 2021 proposal, the EPA found that 112 unique tribal 
lands are located within 50 miles of an affected oil and natural gas 
source, and 32 tribes have one or more oil or natural gas sources on 
their lands.\344\ 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 supplemental 
proposal does not directly impose specific requirements on designated 
facilities, including those located in Indian country. Before 
developing any standards for sources on Tribal land, the EPA would 
consult with leaders from affected tribes.
---------------------------------------------------------------------------

    \344\ 86 FR 63143 (November 15, 2021).
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    After the November 2021 proposal, the EPA held consultation with 
the Mandan, Hidatsa, and Arikara Nation (January 24, 2022), the 
Northern Arapaho Tribe (January 24, 2022), and the Eastern Shoshone 
Tribe (January 25, 2022).\345\ Consistent with previous actions 
affecting the Crude Oil and Natural Gas source category, the EPA 
understands there is continued significant tribal interest because of 
the growth of the oil and natural gas production in Indian country. In 
accordance with the EPA Policy on Consultation and Coordination with 
Indian Tribes, the EPA will continue to engage in consultation with 
tribal officials during the development of this supplemental proposal.
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    \345\ See memorandums located at Docket ID No. EPA-HQ-OAR-2021-
0317.
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G. Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks

    This action is subject to E.O. 13045 (62 FR 19885; April 23, 1997) 
because it is an economically significant regulatory action as defined 
by E.O. 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 finalized 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 (74 FR 66524). The 
assessment literature since 2009 strengthens these conclusions by 
providing more detailed findings regarding these groups' 
vulnerabilities and the projected impacts they may experience (e.g., 
the 2016 Climate and Health Assessment).\346\ 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

[[Page 74846]]

detailed information on the impacts of climate change to human health 
and welfare is provided in sections III and VI of the November 2021 
proposal \347\ and section VII of this preamble.
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    \346\ USGCRP, 2016: The Impacts of Climate Change on Human 
Health in the United States: A Scientific Assessment. Crimmins, A., 
J. Balbus, J.L. Gamble, C.B. Beard, J.E. Bell, D. Dodgen, R.J. 
Eisen, N. Fann, M.D. Hawkins, S.C. Herring, L. Jantarasami, D.M. 
Mills, S. Saha, M.C. Sarofim, J. Trtanj, and L. Ziska, Eds. U.S. 
Global Change Research Program, Washington, DC, 312 pp. http://dx.doi.org/10.7930/J0R49NQX.
    \347\ See 86 FR 63124 and 86 FR 63139 (November 15, 2021).
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H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use

    This action, which is a significant regulatory action under 
Executive Order 12866, has a significant adverse effect on the supply, 
distribution or use of energy. The documentation for this decision is 
contained in the 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 prepared for the November 2021 proposal and the 
Regulatory Impact Analysis of the Supplemental Proposal for the 
Standards of Performance for New, Reconstructed, and Modified Sources 
and Emissions Guidelines for Existing Sources: Oil and Natural Gas 
Sector Climate Review for this action \348\
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    \348\ See Document ID No. EPA-HQ-OAR-2021-0317-0173.
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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 instrumental 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 10, 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.'' \349\ In this document, the EPA is proposing to include in a 
final rule regulatory text for 40 CFR part 60, subpart OOOOb and OOOOc 
that includes incorporation by reference. In accordance with 
requirements of 1 CFR part 51, the EPA is proposing to incorporate the 
following ten standards by reference.
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    \349\ See Document ID No. EPA-HQ-OAR-2021-0317-0072.
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     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, kerosenes, 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

[[Page 74847]]

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: ASTM International (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 website: https://nepis.epa.gov/Adobe/PDF/P100EKJR.pdf.
    The EPA welcomes comments on this aspect of the proposed rulemaking 
and, specifically, invites the public to identify potentially 
applicable VCS and to explain why such standards should be used in this 
regulation.

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

    This action does not have disproportionately high and adverse human 
health or environmental effects on minority populations, low-income 
populations, and/or indigenous peoples, as specified in Executive Order 
12898 (59 FR 7629; February 16, 1994). The documentation for this 
assessment is contained in section 4 of the 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 prepared for the November 2021 
proposal and in section 4 of the Regulatory Impact Analysis of the 
Supplemental Proposal for the Standards of Performance for New, 
Reconstructed, and Modified Sources and Emissions Guidelines for 
Existing Sources: Oil and Natural Gas Sector Climate Review prepared 
for this action.\350\
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    \350\ See Document ID No. EPA-HQ-OAR-2021-0317-0173.
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List of Subjects in 40 CFR Part 60

    Environmental protection, Administrative practice and procedure, 
Air pollution control, Incorporation by reference; Reporting and 
recordkeeping requirements.

Michael S. Regan,
Administrator.
[FR Doc. 2022-24675 Filed 12-5-22; 8:45 am]
BILLING CODE 6560-50-P